Download IEEE Std 1204-1997, IEEE Guide for Planning DC Links Terminating

IEEE Std 1204-1997
IEEE Guide for Planning DC Links
Terminating at AC Locations Having
Low Short-Circuit Capacities
Sponsor
Transmission and Distribution Committee
of the
IEEE Power Engineering Society
Approved 26 June 1997
IEEE Standards Board
Abstract: Guidance on the planning and design of dc links terminating at ac system locations having low short-circuit capacities relative to the dc power infeed is provided in this guide. This guide is
limited to the aspects of interactions between ac and dc systems that result from the fact that the ac
system is ÒweakÓ compared to the power of the dc link (i.e., ac system appears as a high impedance
at the ac/dc interface bus). This guide contains two parts: Part I, AC/DC Interaction Phenomena,
classiÞes the strength of the ac/dc system, provides information about interactions between ac and
dc systems, and gives guidance on design and performance; and Part II, Planning Guidelines, considers the impact of ac/dc system interactions and their mitigation on economics and overall system
performance and discusses the studies that need to be performed.
Keywords: ac/dc interaction, fault recovery, frequency instability, harmonic transfer, instability, low
short-circuit ratio (SCR), power, resonance, subsynchronous torsional interaction, temporary overvoltage (TOV), voltage instability
The Institute of Electrical and Electronics Engineers, Inc.
345 East 47th Street, New York, NY 10017-2394, USA
Copyright © 1997 by the Institute of Electrical and Electronics Engineers, Inc.
All rights reserved. Published 1997. Printed in the United States of America.
ISBN 1-55937-936-7
No part of this publication may be reproduced in any form, in an electronic retrieval system or otherwise, without the prior
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Introduction
(This introduction is not part of IEEE Std 1204-1997, IEEE Guide for Planning DC Links Terminating at AC Locations
Having Low Short-Circuit CapacitiesÑPart I: AC/DC Interaction Phenomena; Part II: Planning Guidelines.)
The purpose of this document is to give guidance on the planning and design of dc links terminating at ac
system locations having low short-circuit capacities relative to the dc power infeed. This guide is limited to
the aspects of interactions between ac and dc systems that result from the fact that the ac system is ÒweakÓ
compared to the power of the dc link (i.e., ac system appears as a high impedance at the ac/dc interface bus).
Some more general aspects of the design and planning of high-voltage dc transmission schemes are
described only when this adds to the understanding of the interaction phenomena and for the sake of completeness of the guide.
The content of this guide is put into practical perspective through reference to experience from existing systems. It explains how special ac/dc interaction problems, in a low or very low short-circuit ratio situation,
were considered during system planning; what speciÞc solutions were applied; and the subsequent operating
experience.
This guide contains two parts:
Ñ
Ñ
Part I, AC/DC Interaction Phenomena, classiÞes the strength of the ac/dc system, provides information
about interactions between ac and dc systems, and provides guidance on design and performance.
Part II, Planning Guidelines, considers the impact of ac/dc system interactions and their mitigation
on economics and overall system performance and discusses the studies that need to be performed.
Part I is separated into the following clauses:
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Clause 1 contains general introductory and useful reference information.
Clauses 2 and 3 discuss the strength of the ac/dc systems and their effects on voltage stability and
power transfer limits.
Clause 4 discusses HVDC controls and protection because they play an important role in most interaction phenomena.
Clause 5 provides information about resonances, instabilities, and harmonic transfers.
Clause 6 examines subsynchronous torsional interactions between dc convertors and nearby turbine
generators.
Clause 7 discusses the various types of ac system stabilities (i.e., transient, steady-state, lowfrequency, and power-frequency stabilities).
Clause 8 explains temporary overvoltages.
Clause 9 examines rotational inertia of an ac system, which is an important aspect of the performance of an ac/dc link.
Clause 10 describes the recovery of dc systems from ac and dc system faults.
Annex A gives a brief description of the dc conversion process (i.e., basic rectiÞer and inverter operation).
Annex B provides a bibliography pertaining to Part I. While it is not essential reference material for
Part I of this guide, and while no claim is made that it is an exhaustive list, it is a useful resource of
background information.
Part II is separated into the following clauses:
Ñ
Ñ
Ñ
Clause 1 contains general introductory and useful reference information.
Clause 2 contains references.
Clause 3 sets the stage for planning and design by identifying performance criteria and explains how
these criteria can be deÞned and evaluated. This clause provides the basis for considering interaction
and for evaluating the effectiveness of adopted strategies.
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iii
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Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Clause 4 discusses various aspects of system performance, in the context of low and very low shortcircuit ratios, for the incorporation of the criteria developed in Clause 3. Alternative solutions to
accommodate ac/dc interaction problems are presented.
Clause 5 deals with aspects of economics and reliability.
Clause 6 provides guidance on appropriate planning studies, once a dc link has been selected, with
particular reference to low and very low SCR applications. After a review of appropriate study methods, both analog and digital, the stages of planning and design are suggested, and guidance is offered
on which aspects to include.
Clause 7 summarizes examples from the literature, in the context of planning studies for low SCR dc
projects.
Clause 8 describes selected projects that are in service with low and very low short-circuit ratios.
Annex A provides a bibliography pertaining to Part II. While it is not essential reference material for
Part II of this guide, and while no claim is made that it is an exhaustive list, it is a useful resource of
background information.
This guide is the result of the work of the Joint Task Force (JTF) of the CIGRƒ Working Group 14.07ÑAC/
DC System Interactions, and IEEE Working Group 15.05.05ÑInteraction with Low SCR AC Systems, which
was set up in 1986 following the agreement between D. D. Wilson, Chairman of the IEEE Transmission and
Distribution Committee, and T. E. Calverley, Chairman of the CIGRƒ Study Committee 14ÑDC Links.
At the time this guide was completed, the membership of the respective working groups were as follows:
IEEE Working Group 15.05.05:
P. C. S. Krishnayya, Chair
R. Adapa
G. Andersson
M. Baker
L. A. Bateman
L. Bergstrom
J. P. Bowles
G. D. Breuer
R. Bunch
D. G. Chapman
D. J. Christofersen
C. D. Clarke
P. Danfors
C. C. Diemond
J. J. Dougherty
A. Ekstrom
T. F. Garrity
A. Gavrilovic*
A. E. Hammad
R. E. Harrison
D. P. Hartmann
N. G. Hingorani
M. Holm
R. K. Johnson
G. W. Juette
G. G. Karady
W. O. Kramer
J. M. Ladden
C. M. Lane, Jr.
E. V. Larsen
R. H. Lasseter
R. L. Lee
T. H. Lee
M. A. Lebow
S. Lefebvre
J. Lemay
H. P. Lips
W. Litzenberger
W. F. Long
D. J. Lorden
J. S. McConnach
M. F. McGranaghan
D. Melvold
A. J. Molnar
K. Mortensen
S. Nilsson
S. Nyati
H. S. Patel
C. Peixoto
K. J. Peterson
R. J. Piwko
D. Povh
F. S. Prabhakara
J. Reeveà
J. Slapp
J. P. Stovall
M. Z. Tarnawecky
R. Thallum
C. V. Thio
D. R. Torgerson
J. J. Vithayathil
T. L. Weaver
D. A. Woodford
C. T. Wu
* Co-chair of JTF
Technical Editor for Part I
à Technical Editor for Part II
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CIGRƒ Working Group 14.07:
A. Gavrilovic, Chair
P. Adam
T. Adielson
J. D. Ainsworth
G. Andersson
J. P. Bowles
G. D. Breuer
P. H. Buxton
A. E. Hammad
B. Hansson
R. E. Harrison
R. Joetten
R. K. Johnson
Y. Kato
V. V. Khoudiakov
P. C. S. Krishnayya
R. H. Lasseter
J. Lemay
G. Liss
W. F. Long
J. McConnach
V. V. Mogirev
G. Moraw
F. Nozari
C. A. O. Peixoto
D. Povh
J. Reeve
M. Szechtman
H. L. Thanawala
C. Thio
P. L. Thomsen
T. L. Weaver
R. Yacamini
The following persons were on the balloting committee:
J. E. Applequist
J. J. Burke
V. L. Chartier
C. C. Diemond
I. S. Grant
J. G. Kappenman
G. G. Karady
C. P. Krishanyya
J. Lemay
W. F. Long
D. J. Melvold
F. D. Myers
When the IEEE Standards Board approved this guide on 26 June 1997, it had the following membership:
Donald C. Loughry, Chair
Clyde R. Camp
Stephen L. Diamond
Harold E. Epstein
Donald C. Fleckenstein
Jay Forster*
Thomas F. Garrity
Donald N. Heirman
Jim Isaak
Ben C. Johnson
Richard J. Holleman, Vice Chair
Andrew G. Salem, Secretary
Lowell Johnson
Robert Kennelly
E. G. "Al" Kiener
Joseph L. KoepÞnger*
Stephen R. Lambert
Lawrence V. McCall
L. Bruce McClung
Marco W. Migliaro
Louis-Fran•ois Pau
Gerald H. Peterson
John W. Pope
Jose R. Ramos
Ronald H. Reimer
Ingo RŸsch
John S. Ryan
Chee Kiow Tan
Howard L. Wolfman
*Member Emeritus
Also included are the following nonvoting IEEE Standards Board liaisons:
Satish K. Aggarwal
Alan H. Cookson
Paula M. Kelty
IEEE Standards Project Editor
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Contents
Part I: AC/DC Interaction Phenomena
1.
Overview.............................................................................................................................................. 1
1.1
1.2
1.3
1.4
1.5
1.6
2.
Scope............................................................................................................................................ 1
Purpose......................................................................................................................................... 1
General......................................................................................................................................... 1
References.................................................................................................................................... 3
Definitions.................................................................................................................................... 3
Acronyms and abbreviations........................................................................................................ 4
AC/DC system strength ....................................................................................................................... 5
2.1
2.2
2.3
2.4
2.5
2.6
Introduction.................................................................................................................................. 5
High-impedance systems ............................................................................................................. 5
Inadequate and zero mechanical inertia..................................................................................... 21
Numerical examples of CSCRs and TOVfc values.................................................................... 23
Calculation of CSCRs ................................................................................................................ 24
Numerical examples of power reduction due to ac system impedance increase
and ac voltage reduction ............................................................................................................ 27
2.7 AC/DC system strengthÑsummary tables ................................................................................ 28
3.
DC power transfer limits.................................................................................................................... 28
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
4.
Description of phenomena ......................................................................................................... 28
Power limits of an inverter......................................................................................................... 32
Power limits of a dc link ............................................................................................................ 36
Principal parameters................................................................................................................... 40
Trends and sensitivities of system parameters........................................................................... 40
Possible improvements .............................................................................................................. 41
Influence of dc controls ............................................................................................................. 43
Methods of study........................................................................................................................ 43
Discussion of power curves ....................................................................................................... 44
Control and protection for dc transmission........................................................................................ 46
4.1 Introduction................................................................................................................................ 46
4.2 Hierarchical division of the dc control system .......................................................................... 46
4.3 Types of interaction between controls and the ac system.......................................................... 49
4.4 Current control ........................................................................................................................... 51
4.5 Power control ............................................................................................................................. 56
4.6 Reduction of the direct current at low voltage........................................................................... 56
4.7 AC system instabilities .............................................................................................................. 57
4.8 Influence on the control of resonances in the ac network.......................................................... 58
4.9 Summary of convertor control instability phenomena............................................................... 58
4.10 System parameters of principal interest to the controls ............................................................. 59
4.11 AC voltage variations ................................................................................................................ 59
4.12 AC network frequency and stabilization control ....................................................................... 62
4.13 Control and protection considerations for back-to-back schemes ............................................. 67
4.14 Control and protection considerations for multiterminal schemes ............................................ 68
4.15 Higher-level controller characteristics for dc schemes in operation.......................................... 68
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4.16 Protection ................................................................................................................................... 72
5.
Resonances, instabilities, and harmonic transfer ............................................................................... 73
5.1
5.2
5.3
5.4
5.5
5.6
5.7
5.8
6.
Subsynchronous torsional interactions between dc convertors and nearby turbine-generators ........ 81
6.1
6.2
6.3
6.4
6.5
6.6
7.
Introduction................................................................................................................................ 89
Descriptions of stability types.................................................................................................... 89
Main parameters and effects ...................................................................................................... 90
Trends and sensitivities of system parameters........................................................................... 91
AC and dc parallel operation ..................................................................................................... 92
Influence of dc control ............................................................................................................... 92
Methods and tools for study....................................................................................................... 93
Different types of schemes......................................................................................................... 94
Temporary overvoltages (TOVs)....................................................................................................... 95
8.1
8.2
8.3
8.4
8.5
8.6
8.7
9.
Introduction and summary ......................................................................................................... 81
Description of the phenomenon ................................................................................................. 82
Principal parameters................................................................................................................... 82
Trends and sensitivities of system parameters........................................................................... 84
Influence of dc controls ............................................................................................................. 85
Methods of study........................................................................................................................ 87
Transient, steady-state, low-frequency, and power-frequency stabilities.......................................... 89
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
8.
Introduction................................................................................................................................ 73
Basic concepts............................................................................................................................ 73
Harmonic resonance-related instabilities and solutions............................................................. 75
Factors influencing harmonic problems..................................................................................... 79
Trends and sensitivities of system parameters........................................................................... 79
Methods of study........................................................................................................................ 79
Different types of schemes and harmonic problems.................................................................. 80
Comments .................................................................................................................................. 81
Description of phenomena ......................................................................................................... 95
Main parameters affecting the phenomena ................................................................................ 97
Trends and sensitivities of the system parameters..................................................................... 97
Influence of dc control ............................................................................................................... 98
Methods and tools for study....................................................................................................... 98
Measures for the limitation of TOVs ....................................................................................... 101
Different types of schemes....................................................................................................... 103
Zero- and low-inertia systems.......................................................................................................... 104
9.1 Introduction.............................................................................................................................. 104
9.2 Zero-inertia systemsÑIsland of Gotland................................................................................. 105
9.3 Low-inertia systemÑIsland of Corsica ................................................................................... 107
10.
Recovery of dc systems from ac and dc system faults..................................................................... 109
10.1 Introduction.............................................................................................................................. 109
10.2 Parametric behavior of the phenomena.................................................................................... 110
10.3 Different types of schemes....................................................................................................... 115
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10.4 System experience and examples............................................................................................. 117
10.5 Methods and tools for studies .................................................................................................. 121
Annex A (informative) The dc conversion process ..................................................................................... 123
Annex B (informative) Bibliography........................................................................................................... 135
Part II: Planning Guidelines
1.
Overview.......................................................................................................................................... 141
1.1 Scope........................................................................................................................................ 141
1.2 Purpose..................................................................................................................................... 141
1.3 General..................................................................................................................................... 141
2.
References........................................................................................................................................ 142
3.
Performance criteria and evaluation ................................................................................................ 142
3.1 General considerations............................................................................................................. 142
3.2 Power transfer limits and SCR................................................................................................. 143
3.3 Recovery from ac and dc faults ............................................................................................... 145
3.4 Reactive compensation ............................................................................................................ 145
3.5 Temporary overvoltages (TOVs)............................................................................................. 146
3.6 Operation under low ac voltage conditions ............................................................................. 146
3.7 Power transfer during ac and dc faults..................................................................................... 147
3.8 Operation with and without ground return............................................................................... 148
3.9 DC line re-energization............................................................................................................ 148
3.10 Overload considerations........................................................................................................... 148
3.11 Operation without communication .......................................................................................... 149
3.12 Commutation failures............................................................................................................... 149
3.13 Voltage changes during reactive switching ............................................................................. 149
3.14 Availability (adequacy and security) ....................................................................................... 150
3.15 Economic and reliability criteria for comparison of different solutions to
interaction problems................................................................................................................. 150
3.16 Multiterminal considerations ................................................................................................... 150
4.
Planning considerations ................................................................................................................... 151
4.1
4.2
4.3
4.4
4.5
4.6
5.
System economics and reliability .................................................................................................... 164
5.1
5.2
5.3
5.4
6.
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General aspects ........................................................................................................................ 151
Power transfer limits ................................................................................................................ 152
Electromechanical stability...................................................................................................... 157
Planning considerations of HVDC controls............................................................................. 159
Planning of ac/dc performance enhancement .......................................................................... 163
Consideration of existing dc schemes in the same system ...................................................... 164
General considerations............................................................................................................. 164
Aspects of alternative solutions to solve ac/dc interaction problems ...................................... 165
Reliability and economic aspects of different dc system configurations................................. 167
Study methods, sources of data, and assumptions ................................................................... 168
Planning and initial design studies................................................................................................... 170
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6.1
6.2
6.3
6.4
7.
Examples of system studies ............................................................................................................. 181
7.1
7.2
7.3
7.4
7.5
7.6
7.7
7.8
7.9
8.
Introduction.............................................................................................................................. 170
Planning studies ....................................................................................................................... 170
Initial design studies ................................................................................................................ 173
Required system data ............................................................................................................... 179
Introduction.............................................................................................................................. 181
Itaipu transmission system....................................................................................................... 181
Chateauguay............................................................................................................................. 182
Highgate................................................................................................................................... 182
Gotland..................................................................................................................................... 183
Virginia Smith (formerly Sidney)............................................................................................ 183
MTDC system studies.............................................................................................................. 183
Reliability studies..................................................................................................................... 184
Additional references ............................................................................................................... 184
Examples of existing low and very low SCR systems..................................................................... 184
8.1 Introduction.............................................................................................................................. 184
8.2 Miles City converter station..................................................................................................... 186
8.3 Virginia Smith (formerly Sidney) ........................................................................................... 188
8.4 Highgate................................................................................................................................... 190
8.5 Chateauguay............................................................................................................................. 191
8.6 Blackwater .............................................................................................................................. 191
8.7 Cross Channel ......................................................................................................................... 192
8.8 Vindhyachal ............................................................................................................................. 193
8.9 Gotland..................................................................................................................................... 194
8.10 Comerford ................................................................................................................................ 195
8.11 Nelson River ........................................................................................................................... 196
8.12Itaipu ........................................................................................................................................ 197
8.13 McNeill .................................................................................................................................... 198
Annex A (informative) Bibliography........................................................................................................... 201
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IEEE Guide for Planning DC Links Terminating at
AC Locations Having Low Short-Circuit Capacities
Part I: AC/DC Interaction Phenomena
1. Overview
1.1 Scope
Part I of the guide discusses the effects of various aspects of the ac/dc interactions on the design and performance of dc schemes where the ac system appears as a high impedance at the ac/dc interface bus; i.e., low
and very low short-circuit (short-circuit ratio [SCR]) conditions. AC systems having zero or inadequate
mechanical rotational inertia, such as island schemes with no or with limited local generation, are also considered. Environmental, siting, and construction issues are not addressed. General issues, such as steadystate reactive compensation and ac and dc Þlter requirements, are not in the scope of this guide, but would be
included in a complete study for a particular dc scheme design. In order to assist those not familiar with dc
transmission and convertors, a brief description of basic rectiÞer and inverter operation is given in Annex A
of Part I.
Part II of this guide, which is bound together with Part I, considers how the ac/dc interaction phenomena
described in Part I should be taken into account in the planning and the preliminary design of ac/dc systems
having low or very low SCR values.
1.2 Purpose
The purpose of Part I of this guide is to address factors required to be considered in the design of dc transmission schemes in the context of system interactions resulting from dc links terminating at ac system locations having low short-circuit capacities relative to dc power infeed and for cases where the inertia of the ac
system is too low for satisfactory operation. The following ac/dc interactions are considered: power, voltage,
and frequency instabilities; harmonic resonance-related instabilities; subsynchronous torsional interactions;
temporary overvoltages; and recoveries from ac and dc faults.
1.3 General
The introduction of thyristor valves based on large-size thyristors, over the last twenty years, has contributed
to the improvement of overall high-voltage, direct-current (HVDC) economy and reliability, making the
application of HVDC transmission more widespread.
From earliest commercial applications of HVDC, planners found, in a number of schemes, that the ac system at the point of the proposed dc power infeed was ÒweakÓÑthat is, its impedance relative to the dc power
was high, and in some cases, the inertia of the ac system was low.
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IEEE
Std 1204-1997
IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
One of the important criteria in the design of dc links is the value of the permissible temporary overvoltage
(TOV) at ac terminals of the convertor stations. In early schemes, the problem of too-high TOV was solved
by the addition of synchronous compensators in the inverter stations; i.e., by the reduction of the ac system
impedance as seen by the HVDC convertor. The application of metal-oxide (MO) arrestors has been made in
some recent schemes to control TOV without the need for synchronous compensators. However, for a given
dc power, this resulted in the need to accept an ac system having higher impedance compared to previous
schemes, and several aspects of interactions between ac and dc systems became more evident.
The Òweaker the ac systemÓÑthat is, the lower the ratio of the ac system short-circuit capacity to dc link
powerÑthe greater will be the ac/dc interactions. The ac/dc system strength, from the impedance point of
view, is deÞned in this guide. Based on that deÞnition and on typical inverter characteristics (such as the value
of the convertor transformer reactance) the following SCR values can be used to classify an ac/dc system:
a)
b)
c)
A high SCR ac/dc system is categorized by an SCR value greater than 3.
A low SCR ac/dc system is categorized by an SCR value between 2 and 3.
A very low SCR ac/dc system is categorized by an SCR value lower than 2.
It should be emphasized that a scheme may be operating with high SCR for most of the time, but that it may
appear as a low or very low SCR scheme during an emergency; that is, at ac system outage conditions. In
such cases, the scheme must be designed to operate for those conditions, unless dc power reduction is
acceptable.
Operation with very low SCR systems is possible only if very fast and continuous control of ac voltage is
exercised, because the inverter operation is in the ÒunstableÓ region of the ac voltage/dc power characteristic.
In modern ac system terms, this mode of operation is similar to an ac system whose voltage stability is maintained by a fast static var compensator (SVC). In such dc links presently in service, the required fast voltage
control is executed by the HVDC convertor itself.
From the above, it can be seen that problems associated with very low SCR ac systems can be resolved
either by strengthening the system with the addition of synchronous compensators or by stabilizing the ac
system voltage with very fast control. On the other hand, synchronous compensators must be used to
strengthen the system whenever there is a requirement to increase the inertia of the ac system. The system
inertia constant referred to dc power, HDC, should, for example, be greater than 2 s in order to maintain frequency deviation under fault conditions at less than 5%.
In addition to the system strength classiÞcation mentioned above, Part I of this guide deÞnes and discusses a
number of ac/dc interaction phenomena and proposes methods of preventing associated potential problems.
Good preliminary judgement on the impact of most interactions on the design and performance of a dc transmission scheme can be based on the SCR and inertia values quoted above, and on the discussions given in
this document. However, this guide stresses the need to carry out adequate studies at all stages of planning
and design.
HVDC controls play an important role in most interaction phenomena, and for that reason a detailed description of controls is included in this guide.
AC/DC system interactions are concerned with voltage stability (voltage collapse phenomena), overvoltages, resonances, and recovery from disturbances. Examples of their inßuence on the station design are the
following:
Ñ
2
Voltage stability conditions will determine the type of voltage control and the type of reactive power
supply. The voltage stabilityÐvoltage collapse interaction is similar to such phenomena in a purely ac
system.
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
Ñ
Ñ
IEEE
Std 1204-1997
The level of TOV will inßuence station design, including thyristor valve and surge arrester ratings.
The lower the value of SCR, the higher the potential value of TOV.
Shunt capacitors are used in convertor stations for ac Þlters and for var supply. The larger the ratio of
shunt capacitor Mvar to ac system short-circuit MVA, the lower will be the resonant frequency.
Commutation failures and recovery from ac and dc faults represent an important aspect of dc operation.
However, it should be noted that modern controls have a dominating inßuence on the recovery from faults
and are less affected by ac system impedance compared to controls used in earlier schemes.
1.4 References
This standard shall be used in conjunction with the following publications. When the following standards are
superseded by an approved revision, the revision shall apply:
IEC 60919-1 (1988-12), Performance of high-voltage d.c. (HVDC) systemsÑPart 1: Steady-state conditions.1
IEC 60919-2 (1990-10), Performance of high-voltage d.c. (HVDC) systemsÑPart 2: Faults and switching.
(Equivalent to IEEE P1030.2/D4, Dec. 1990.2)
IEC 60919-3...3, Performance of high-voltage d.c. (HVDC) systemsÑPart 3: Dynamic conditions.
1.5 DeÞnitions
1.5.1 critical short-circuit ratio (CSCR): The SCR corresponding to the operation at maximum available
power (MAP); for typical inverter design, CSCR = 2.
NOTEÑ The following operational characteristics are associated with CSCR:
Ñ CSCR represents the borderline between ÒstableÓ and ÒunstableÓ operating regions. For SCR values lower
than CSCR, the operation is in the ÒunstableÓ region of the ac voltage/dc power characteristic.
Ñ If the operation is at unity power factor for systems at CSCR (i.e., the operation is at MAP), then the fundamental component of the temporary overvoltage (TOVfc) at full load rejection would be near to 2 .
Ñ A resonance near the second harmonic will occur for systems operating at CSCR.
1.5.2 effective dc inertia constant (Hdc): The rotational ac system inertia constant H converted to the base
of dc power.
1.5.3 high-impedance ac system: An ac/dc system having low or very low SCR. (In this guide, rated values
are assumed to be equal to nominal.)
1.5.4 inadequate inertia systems: An ac system having limited local generation, and therefore rotational
inertia, so that the required voltage and frequency cannot be adequately maintained during transient ac or dc
faults.
1IEC
publications are available from IEC Sales Department, Case Postale 131, 3, rue de VarembŽ, CH-1211, Gen•ve 20, Switzerland/
Suisse. IEC publications are also available in the United States from the Sales Department, American National Standards Institute, 11
West 42nd Street, 13th Floor, New York, NY 10036, USA.
2Numbers preceded by P are IEEE authorized standards projects that were not approved by the IEEE Standards Board at the time this
publication went to press. For information about obtaining drafts, contact the IEEE.
3This IEC standard was not published at the time this publication went to press. Publication is expected in Spring 1998. For information
about obtaining a draft, contact the IEC.
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1.5.5 maximum available power (MAP): The maximum power that can be obtained by increasing dc current while not controlling the ac voltage.
1.5.6 operation with minimum constant g: Operation of an inverter at minimum commutation margin
angle g in order to ensure transmission at the maximum dc voltage (possible only at powers below MAP; i.e.,
in the ÒstableÓ region of the ac voltage/dc power characteristic).
1.5.7 operation with variable g: Margin angle g is varied around an average value in order to stabilize the ac
voltage. This can be achieved either by direct control of the ac voltage or by indirectly controlling the dc
voltage. Another way of stabilizing the receiving system ac voltage is to arrange for the inverter, and not the
rectiÞer, to be the current-controlling station. These modes of control are normally used for operation
beyond MAP; that is, in the ÒunstableÓ region of the ac voltage/dc power characteristic.
1.5.8 short-circuit ratio (SCR): The ratio of the ac system three-phase short-circuit MVA (expressing the
ac system impedance) to dc power.
1.5.9 weak ac system: See: high-impedance ac system.
1.5.10 zero inertia system: An isolated ac system having no local generation.
1.6 Acronyms and abbreviations
ac
AVR
C
CCA
CESCR
CQESCR
CSCR
dc
emf
EMTP
EPRI
ESCR
FSPC
GTO
LVCL
MAP
MO
MPC
MTDC
OLTC
OSCR
PMC
QESCR
RAS
SC
SCR
SR
SSDC
SSO
SVC
TCR
4
alternating current
automatic voltage regulator
capacitor
current control ampliÞer
critical effective short-circuit ratio
critical Q (reactive) effective short-circuit ratio
critical short-circuit ratio
direct current
electromotive force
electromagnetic transients program
Electric Power Research Institute
effective short-circuit ratio
frequency-sensitive power controller
gate turn-off thyristor
low-voltage current limit
maximum available power
metal-oxide
maximum power curve
multi-terminal direct current
on load tap-changes
operating short-circuit ratio
pole master control
Q (reactive) effective short-circuit ratio
remedial action scheme
synchronous compensator
short-circuit ratio
saturated reactor
supplementary subsynchronous damping control
subsynchronous oscillation
static var compensator
thyristor-controlled reactor
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
TCU
TOV
TSC
UIF
VCO
VDCOL
VSF
IEEE
Std 1204-1997
thyristor control unit
temporary overvoltage
thyristor-switched capacitor
unit interactional factor
voltage-controlled oscillator
voltage-dependent current order limit
voltage stability factor
2. AC/DC system strength
2.1 Introduction
Alternating-current system disturbances can affect the operation of any convertor, but mal-operation of a
small convertor should have negligible effect on the ac system. However, it is not uncommon for a dc link to
supply a large proportion of the ac system load so that the loss of its real power and the associated reactive
power changes can have a profound effect on the system.
The interaction between ac and dc systems becomes more pronounced as the impedance of the ac system, as
seen from the convertor ac terminals, is increased for a particular dc power. It follows that even a relatively
small dc link connected to a point of the ac system having high impedance (low short-circuit capacity) may
have considerable effect on the local ac network, even if the latter may be part of a large ac system.
It is important that an adequate system electromotive force (emf) is available not only for normal operation,
but also following a system fault. The rotational mechanical inertia of the ac system transiently provides the
energy to maintain the system emf despite a temporary reduction in the supply of dc power through the
inverter. The ac system generators and their turbines are the main source of the ac system rotational inertia.
If a system receives all or most of its power from a dc link, the inertia of the receiving system may be inadequate, so that upon the interruption of the dc infeed, due to any cause, the system emf and frequency may
decrease to unacceptably low values. In such cases synchronous compensators are used to act as Òtransient
generatorsÓ to maintain the system emf and frequency.
An ac system can be deÞned as ÒweakÓ from two aspects:
a)
b)
Alternating-current system impedance may be high relative to dc power at the point of connection.
Alternating-current system mechanical inertia may be inadequate relative to the dc power infeed.
2.2 High-impedance systems
2.2.1 Short-circuit ratios (SCRs)
2.2.1.1 Calculating SCRs
The calculation of SCRs is discussed in 2.2.5, which shows that it is really per unit (pu) admittance. However, for most practical cases this is not very different from that of pure inductance, and the SCR is then
often obtained from the following equation:
S
SCR = -------P d1
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(1)
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where S is the ac system three-phase symmetrical short-circuit level in megavolt-amperes (MVA) at the convertor terminal ac bus with 1.0 pu ac terminal voltage, and Pd1 is the rated (considered in this guide to be
equal to the nominal) dc terminal power in megawatts (MW).
When considering the effects of short-circuit currents on equipment, only the maximum value needs to be
calculated. In contrast, it is the minimum value of S at which the rated power Pd1 will be transmitted that
must be used when examining limiting operating conditions.
2.2.1.2 Effective short-circuit ratio (ESCR)
Shunt capacitors including ac Þlters connected at the ac terminal of a dc link can signiÞcantly increase the
effective ac system impedance. To allow for this, the effective short-circuit ratio (ESCR) is deÞned as follows:
SÐQ
ESCR = ---------------c
P d1
(2)
where Qc is the value of three-phase fundamental Mvar in per unit of Pd1 at per unit ac voltage of shunt
capacitors connected to the convertor ac bars (ac Þlters and plain shunt banks).
2.2.1.3 Operating short-circuit ratio (OSCR)
The ratio S/Pd1 will vary in practice due to changes in ac system conÞguration and due to different levels of
dc power being transmitted. Therefore, it should be remembered that it is the operating short-circuit ratio
(OSCR) that is important, and that refers to actual power and corresponding actual S. Normally, the OSCR
will be higher than the minimum speciÞed SCR of the scheme, particularly at transmission below rated
power. However, the lowest value of OSCR may not necessarily coincide with rated power. For example,
operation at a lower power level may coincide with a system arrangement having higher impedance value
than the one speciÞed for the rated value. It should be borne in mind that, at very low currents, satisfactory
operation may be achieved only at a value of OSCR that has a higher value than the minimum SCR speciÞed
for operation at normal dc currents.
2.2.1.4 Effect of convertor reactive power consumption and QESCR
SCRs are sometimes used as a measure of expected performance of ac/dc systems, but as discussed later, this
can give only an approximate indication, and comparisons between systems made by referring only to their
respective short-circuit ratios can be misleading.
One of the major reasons for different performance of dc systems having the same SCR or ESCR is the convertor reactive consumption, which may differ considerably between the schemes under consideration. The
reactive consumption of the convertor (Qd) (see Annex A of Part I) can vary greatly depending on the operating a or g and on the value of the commutating reactance (usually the convertor transformer leakage reactance). The value of Qd can have a signiÞcant effect on performance, in particular on power transfer limits
and on temporary overvoltages. If the system short-circuit MVA and Qc are referred to the sum of Pd and Qd
rather than to Pd, a better, but still approximate indication of performance can be obtained as can be seen
from examples given in 2.4.
The Q effective short-circuit ratio (QESCR) is deÞned as follows:
S Ð Qc
QESCR = -----------------Pd Ð Qd
6
(3)
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2.2.1.5 Synchronous compensators (SCs) and static var compensators (SVCs)
Synchronous compensators (SCs) contribute directly to the reduction of the ac system impedance, and they
are included in the calculation of short-circuit ratios. SCs have been used to strengthen the ac system at the
terminals of an inverter, this being a more economic solution compared to, for example, addition of a transmission line.
Operation of a dc link terminating at a point of high ac system impedance (i.e., of low short-circuit capacity)
can be enhanced by fast control of ac voltage. This can be done by using the convertors themselves to control
the voltage or by employing a separate thyristor-controlled reactor (TCR) or a saturated reactor (SR) at the
ac terminals of the inverter. Fast control of the ac voltage does, in effect, ÒstrengthenÓ the ac system.
If the ac system has a very high impedance, relative to the power being transmitted (a very low SCR system;
see 2.2.4.3), satisfactory operation can be achieved in two ways:
a)
b)
By strengthening the ac system by, for example, addition of a synchronous compensatorÑand in so
doing, transforming the system to a low SCR system (see 2.2.4.2)
By applying very fast ac voltage control (see 2.2.7)
It is possible to express, approximately, the strengthening of the ac system by fast voltage control in terms of
a reduction of the ac system impedance (see 2.2.7.1). However, it is recommended to ignore this effect when
calculating the short-circuit ratios. The ac voltage control and the dc power controls must be coordinated for
each scheme; also, the convertor or TCR or SR are designed, due to economic considerations, to execute the
voltage control within a predetermined ac voltage range. Later in this document it is emphasized that shortcircuit ratios describe the system only approximately and that operation with very low SCR assumes fast
voltage control.
A static var compensator (SVC) normally consists of an element (TCR, SR) that provides continuously variable vars and one or more of the following elements:
Ñ
Ñ
Ñ
Ñ
Ñ
Fixed shunt Þlters, capacitors, or reactors
Thyristor switched shunt capacitors
Mechanically switched shunt capacitors
Thyristor switched shunt reactors
Mechanically switched shunt reactors
TCR and SR are excluded, as already stated, from the deÞnition of short-circuit ratios, as their effects
depend on their designed range, speed of response, and coordination with other controls. The other elements,
Þxed or mechanically switched, would have to be included for calculating ESCR, because their presence
adds directly to the ac system impedance.
Shunt reactors are usually disconnected for normal operating conditions, but would have to be considered if
normally connected.
2.2.2 Power-current characteristics
2.2.2.1 Maximum power curve (MPC)
For a given ac system impedance and other parameters of the ac/dc system shown in Figure 2-1, there will be
a unique Pd /Id characteristic, shown in Figure 2-2, provided the starting conditions are deÞned. Additionally,
it is assumed that Id changes almost instantaneously in response to the change of a of the rectiÞer; for example,
due to a change in current order. All other quantitiesÑac system emf, g (minimum) of the inverter, tap-changers, automatic voltage regulation (AVR), and the value of shunt capacitors and reactorsÑare assumed not to
have changed. When considering the inverter power capability, it is also assumed that the rectiÞer provides no
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
limitation to the supply of dc current at rated dc voltage. Each subsequent point is calculated by steady-state
equations. These Òquasi-steady-stateÓ characteristics give a good indication of dynamic performance.
ESCR
Pd
SCR
Qd
Ud
SC
Xc
Z
Id
Qc
C
UL
Figure 2-1ÑSimpliÞed representation of a dc link feeding an ac system with shunt
capacitors (Cs) and synchronous compensators (SCs) (if any) at
Figure
2.1busbars
convertor
station
MAP
Pd
MPC For g
Constant
1.0
I MAP
I LIMIT
.5
1.0
Id
Figure 2-2ÑDC powerÑdc current curve for g minimum
The starting conditions are deÞned to be as follows:
Pd = 1.0 pu, Ud = 1.0 pu, UL = 1.0 pu, and Id = 1.0 pu.
(Pd = dc power; UL = ac terminalÑi.e., convertor transformer line-side voltage; Ud = dc voltage of the
inverter; and Id = dc current.)
If the inverter is operated throughout at minimum constant g, the resulting characteristics will represent maximum obtainable power for the system parameters being considered. This curve is termed the maximum
power curve (MPC). Any power can be obtained below MPC by increasing a and g, but power higher than
8
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
MPC can be obtained only if one or more system parameters are changedÑe.g., by reduced system impedance, increased system emf, larger capacitor banks, etc.
A similar MPC curve can be obtained for the rectiÞer at minimum constant a.
2.2.2.2 Maximum available power (MAP)
An MPC exhibits a maximum value, termed maximum available power (MAP) as can be seen in Figure 2-2.
The increase of the current beyond MAP reduces the dc voltage to a greater extent than the corresponding dc
current increase. This could be counteracted by changing the ac system conditionsÑe.g., by controlling the
ac terminal voltage. It should be noted that dPd/dId is positive for operation at dc currents smaller than IMAP,
the current corresponding to MAP; dPd/dId is negative at dc currents larger than IMAP.
2.2.3 Critical short-circuit ratios (CSCRs)
Maximum power curves are plotted in Figure 2-3 for an inverter connected to ac systems having four different strengths. It can be seen that the rated (nominal) operating point A is located at different parts of MPC
for different values of SCR.
1.8
SCR = 1.5 (ESCR = 0.96)
X c = 0.15 pu, g = 18¡
Q c = Q d = 0.54¥Pdn at U L = 1.0 pu
1.6
Pd or UL (pu)
1.4
SCR = 2.0
(1.46)
B'
1.2
SCR = 3.0
(2.461)
1.0
SCR = 4.5
(3.96)
(ÒB-primeÓ)
SCR = 4.5
SCR = 3.0
B
0.8
1.5
0.6
0.4
SCR = 2.0
0.2
DC Power
AC Volts
0
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu)
Figure 2-3ÑVariation of inverter ac terminal voltage
For SCR = 4.5, the operating point A is well below MAP and the one per unit current is considerably smaller
than IMAP = 1.8 pu. For SCR = 3, A is nearer to MAP and IMAP is 1.4 pu. In both of these cases, dPd /dId is
positive.
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For SCR = 1.5, the operating point A is ÒbeyondÓ MAP, corresponding to IMAP = 0.8 pu of rated dc current,
IdN. The value of dPd /dId is negative. It may appear that there is another possible operating point for
SCR = 1.5 at the left of MAP, point B. However, inspection of Figure 2-3 will indicate that the voltage corresponding to point B for SCR = 1.5 is too high to be utilized, as indicated by point B.
When the rated values of Pd, Id, Ud, and UL (all at 1.0 pu) correspond to the maximum point of Pd/Id curve
for operation with minimum g, then the corresponding SCRs are termed critical ratios (critical SCR [CSCR],
critical effective SCR [CESCR], and critical Q effective SCR [CQESCR]).
In this example, CSCR = 2, and the operating point A coincides with the MAP of the curve for SCR = 2.
However, as discussed in 2.4, the value of CSCR depends on the inverter reactive consumption; i.e., on the
values of the commutating reactance Xc and on the commutation margin g.
For calculation of critical short-circuit ratios, see 2.5.
It is clear that the critical short-circuit ratios represent a borderline, when operating at g constant, as the ratio
dPd /dId changes its sign. This is further discussed in Clause 3.
2.2.4 Short-circuit ratios as indication of ac/dc system strength
Three typical cases can be distiguished by considering the transient conditions that would temporarily
reduce the ac terminal voltage and/or increase the system impedance; e.g., due to the loss of an ac line. In
such a case, the power for a given current would be reduced; i.e., the temporary system condition would
result in a new power curve that has a lower maximum value.
2.2.4.1 High SCR system
Figure 2-4 shows an inverter connected to a system by two parallel ac lines. It is assumed that the original
SCR of 4.5 is temporarily reduced to an SCR of 3 if one of the two lines has tripped.
Figure 2-4ÑAn inverter connected to a system by two parallel ac lines
In this case, power can be maintained at one per unit value despite the reduction of MAP, as shown in
Figure 2-5 by increasing dc current at the new operating point, B. Operation throughout is at dc currents having a lower value than the current corresponding to MAP (Id < IMAP). The assumed system disturbances
have resulted in a reduction of MPC, but the new maximum, MAP-2, is still higher than the rated power. All
operating conditions are at g minimum constant and correspond to SCR > CSCR.
(It should be noted that a sufÞciently severe system disturbance could always cause an excursion beyond
MAP, but such rare events are not considered as part of the deÞnition of system strength.)
10
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IEEE
Std 1204-1997
X c = 0.15 pu, g = 18¡
Q c = Q d = 0.54¥Pdn at U L = 1.0 pu (Point A)
1.6
Pd or UL (pu)
1.4
MPC - 1
SCR = 4.5 (3.96)
ESCR = (2.46)
SCR = 3.0
1.2
A
1.0
0.8
MAP -1
MAP -2
SCR = 4.5
(3.96)
MPC -2
SCR = 3.0 (2.46)
B
0.6
0.4
Pd
UL
0.2
DC Power
AC Volts
0
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu)
Figure 2-5ÑAC/DC systemÑhigh SCR, sudden change of SCR from 4.5 to 3.0
2.2.4.2 Low SCR system
The normal operation is at Id < IMAP but a system disturbance could reduce MAP below the rated power and
operation would continue at a reduced power in current control at Id, which may be greater than IMAP, or in
power control at a reduced power order. Normal operating conditions are at SCR > CSCR for operation at
minimum g, but temporary operation may be at SCR < CSCR at a power level lower than rated.
Power curves for this case are shown in Figure 2-6a. It has been assumed that an SCR of three reduces to
a value of two, as a consequence of the tripping of one line (Figure 2-4). The power at MAP-2 of the
reduced MPC-2 is lower than the rated power at A. Any increase of current beyond 1.0 would be counterproductive, as the power would further reduce. It should be noted that the system impedance for curves
SCR = 2 of Figures 2-3 and 2-6a are identical, but MAP-2 of Figure 2-6a has a lower value than MAP for
SCR = 2 of Figure 2-3. The reason for this is that the initial ac terminal voltage, UL, for all values of
SCRs of Figure 2-3 was adjusted at one per unit. In the case of Figure 2-6a, UL was adjusted to one per
unit for initial conditions at SCR = 3. After the line tripping ac terminal voltage was decreased, due to an
increase of the system impedance, to a value of 0.93 pu of ULN and power decreased to 0.92 pu of PdN at
1.0 pu of Id. These values represent the initial conditions for MPC-2.
2.2.4.3 Very low SCR system
Normal operation is at a direct current equal to or larger than the current corresponding to MAP ( Id > IMAP).
Normal operating conditions are at SCR £ CSCR as indicated by point A on a curve for SCR = 1.5 in
Figure 2.3. In such cases, a stable condition in power control is achieved by operation with variable g. The
variable g is normally kept at a value higher than the minimum, so that the inverter itself can control the voltage. An alternative way of operating at SCR < CSCR can be achieved by the use of very fast static var compensators to control the ac voltage, and hence the dc voltage.
The operation with very low SCR systems is discussed in Clauses 3 and 4.
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1.6
Pd or UL (pu)
1.4
SCR = 2.0
X c = 0.15 pu, g = 18¡
Q c = Q d = 0.54¥Pdn at U L = 1.0 pu
1.2
SCR = 3.0
MAP -1
A
1.0
MPC - 1
SCR = 3.0
C
0.8
MAP-2 B
0.6
MPC -2
SCR = 2.0
0.4
Pd
UL
0.2
0
DC Power
AC Volts
I LIMIT
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu)
Figure 2-6aÑAC/DC systemÑlow SCR power and ac voltage curves, sudden change of
SCR from 3.0 to 2.0
2.2.4.4 Typical values of SCR
In the initial stages of planning, the utility may know only the short-circuit MVA of the system and the
required dc MW. The following are very approximate indications of the ac/dc system strength in terms of
SCR.
For a high SCR system (approximately SCR > 3.0) as deÞned in 2.2.4.1, dc could normally be introduced
without the need for any special steps. However, as can be seen from the ac voltage curves of Figure 2-3, the
TOVÑthe value of UL at load rejection (Id = 0)Ñis becoming relatively high as SCR reduces and
approaches the value of three, and ac voltage control has been used for some schemes having SCR in that
region (Cross Channel, Chateauguay).
The application of HVDC with a low SCR system as deÞned in 2.2.4.2 (approximately 3 > SCR > 2) may
need some additional control features (see Clauses 3 and 4). In addition, consideration should be given to ac
voltage control and to the possibility of second/third harmonic resonance. These considerations may result in
the need for some additional steps to be taken.
If SCR is lower than two, the system may prove to be a very low SCR system as deÞned in 2.2.4.3, and the
use of Òvariable g control strategyÓ (see Clauses 3 and 4) may prove to be essential. Operation at constant g
could be possible, provided very fast ac voltage control is used. Special steps would be needed to control ac
overvoltages and low-order harmonics.
When comparing the performance of a dc link based on the values of SCR, it should be appreciated that the
value of CSCR, unlike SCR, depends on the value of Qd, which in turn depends on the commutating reactance,
Xc, and the value of g. Two inverters rated for the same nominal power, but having different nominal Qd, will
have the same SCR, but the values of CSCRs will be different. It can be seen in 2.4 that, for some typical examples, CSCR may vary by more than 30%. In the examples considered in previous subclauses, Xc = 15% and
g = 18° have been assumed, which may be considered to be in the middle of the range of practical values.
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One system may have requirements that necessitate deeper study than another system. System damping,
which in the simple model is represented by the impedance angle, may differ greatly between two systems
having the same value of SCR. This can be important for some interaction phenomena. All meaningful studies should use the available system data in sufÞcient detail to match the requirements of a particular study.
However, it should be noted that the trends in convertor control design are making stability and recovery
from faults less inßuenced by system damping. Hence, in the future, the damping will principally affect the
steady-state harmonics and overvoltages due to major disturbances, such as total load rejection.
2.2.4.5 The nature of ac system disturbance
The deÞnitions of the system strength given in 2.2.4 depend also on the operating conditions of a given system. For example, the disturbance described in 2.2.4.2 may be considered, by some utilities, to be an exceptional event, and more Ònormal,Ó relatively frequent disturbances may not result in the reduction of
maximum available power (MAP-2) below the rated power.
The utilities usually specify the disturbance for which the power should be maintained at the rated value in
terms of the ac terminal voltage reduction, without specifying any associated change of the system impedance; i.e., as if the terminal voltage was reduced only by ac system emf reduction.
The effect on dc power will be different for the same amount of ac terminal voltage reduction, depending on
whether the ac system impedance has changed or not.
In Figure 2-6b, MPC-1 and MPC-2 are the same as in Figure 2-6a: MPC-2 resulted from the ac system
impedance increase by one-third, from SCR = 3 to SCR = 2; this resulted in an ac terminal voltage drop from
1.0 pu (point A) to 0.93 pu (point B) at Id = one per unit; the power has reduced from one per unit to 0.92 pu,
which is very close to the value of MAP-2.
X c = 0.15 pu, g = 18¡
Q c = Q d = 0.54¥Pdn at U L = 1.0 pu
1.6
Pd or UL (pu)
1.4
1.2
1.0
0.8
SCR = 2.0
SCR = 3.0
MAP -1
SCR = 3.0
at Reduced
Voltage
MAP -3
MPC - 1
SCR = 3.0
MAP -2
0.6
MPC -3
SCR = 3.0
at Reduced
Voltage
0.4
0.2
Pd
UL
MPC -2
SCR = 2.0
DC Power
AC Volts
0
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu)
Figure 2-6bÑAC/DC systemÑlow
sudden ac voltage reduction
FigureSCR,
2.6b
without SCR change (MAP-3)
AC/DC System - Low SCR Sudden AC Voltage
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MPC-3 was obtained by assuming that ac terminal voltage has reduced to 0.93 pu without a change of the
system impedance. Direct-current power has reduced initially to a similar value as for MPC-2, but because
MAP-3 has a greater value than MAP-2, the power can be increased to 0.98 pu (MAP-3) by increasing dc
current to 1.25 pu.
This means that the power immediately available following the disturbances will differ by 6.5% for the two
cases.
Relevant quantities for these two cases are tabulated in 2.6.
2.2.4.6 Temporary overvoltages (TOVs)
When considering power transfer limits, MAP represents a clear change in the Pd /Id characteristic. Moreover, for operation at currents higher that IMAP , the control strategy based on constant g operation cannot be
used in power control mode.
When considering the values of TOVs, there is no such deÞnite Òbreak point.Ó In addition, depending on the
location of the convertor station and on the utility practice, the acceptable value of TOV may vary from
scheme to scheme.
Also, in highly meshed systems having generators that are electrically close to the convertor station, the
effective short-circuit impedance corresponding to the SCR value calculated by subtransient reactances will
apply only to the Þrst fundamental cycle, and the subsequent TOV would be higher as transient reactances
rather than subtransient values inßuence the voltages.
The fundamental components of TOV (TOVfc) calculated from Equation (27) in 8.5 have the following
approximate values:
a)
b)
c)
High SCR systems (SCR > 3): TOVfc lower than 1.25 pu
Low SCR systems (3 > SCR > 2): TOVfc higher than 1.25 but lower than 1.4 pu
Very low SCR systems (SCR < 2): TOVfc higher than 1.4 pu
[These are theoretical values, ignoring saturation of transformers; TOVfc values will be lower in reality due
to this (refer to 8.1).] However, the TOV peak values that include harmonic components may not be reduced
by saturation of convertor transformers.
It should be pointed out that operation with low SCR systems does not seem to cause particular difÞculties
from the point of view of transfer of power. Occasional temporary power reduction (see 2.2.4, 3.2.2, and
3.6.2) can be contained. However, the corresponding TOV is not always acceptable.
In Figure 2-7, Pd /Id curve MPC-2 was plotted using data of the Cross Channel scheme. It can be seen that
for SCR = 3 (ACV-2) this would have resulted in TOVfc of just over 1.3 pu, which was not acceptable to the
utility. Static var compensators were included in the installation to limit TOVfc to 1.16 pu. SCR equal to
three is the minimum speciÞed value; the operation is normally at an SCR value higher than three.
It is interesting to compare MPC for the uncompensated Cross Channel scheme with the MPC for the ÒaverageÓ scheme data used in Figures 2-6a and 2-6b for the same SCR = 3. For the ÒaverageÓ system, TOVfc is
just over 1.2 pu, compared to the uncompensated Cross Channel scheme of just over 1.3 pu. This is due to
the difference in the value of the commutating reactance and consequent higher var consumption. The difference in MAP values should also be noted.
14
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MCP-1 X c = 0.15 pu, g = 18¡, Q d = Q c = 0.54¥Pdn at U L = 1.0 pu
MCP-2 X c = 0.23 pu, g = 15¡, Q d = 0.6 Pdn, Qc = 0.52¥Pdn at UL = 1.0 pu
Pd or UL (pu)
1.4
ACV - 2
Cross Channel - SCR 3
(ESCR 2.48, QESCR 1.55)
1.2
1.0
0.8
ACV - 1
From Fig. 2.6
for SCR 3
(ESCR 2.46,
QESCR1.6)
MPC - 1
MPC -2
0.6
0.4
Pd
UL
0.2
DC Power
AC Volts
0
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu)
Figure 2-7ÑPower and ac voltage
curves 2.7
for SCR = 3 for two different convertor
Figure
characteristics
Power and AC Voltage Curves for SCR = 3
2.2.5 Calculation of SCRs
2.2.5.1 General
In many preliminary calculations it is convenient and customary to use a simpliÞed representation of the ac
system, as discussed in 2.2.5.2. To determine the system impedance and SCRs, digital short-circuit programs
from different origins can give different results for SCR for the same system, while giving the correct results
for the normal purpose of these programs, which are usually used for studying ac systems alone. For example, a program may not represent the transmission linesÕ shunt capacitance, which would give unrealistically
low system impedance, Zs , and in consequence, a too-high SCR. Some interaction phenomena are signiÞcantly inßuenced by the system resistive component (system damping), which is primarily provided by
loads, but may not be represented in some short-circuit programs.
2.2.5.2 SimpliÞed representation of the ac/dc system
Referring to Figure 2-1, it is assumed that the ac system can be represented by a Thevenin equivalent emf at
fundamental frequency, behind an impedance Z (or admittance Y = 1/Z).
SCR is deÞned as the value of Y at fundamental frequency, on a base of rated power (MW) of the convertor
and rated ac system voltage, that is consistent with SCR deÞned in 2.2.1. Synchronous compensators, existing or supplied as part of the convertor station, are deemed to be connected as required for the operation considered; i.e., they form part of the SCR calculation.
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ESCR is deÞned as (Y + Yc) on the same base as for SCR, where Yc is the admittance of all shunt Þlters and
capacitor banks on the busbar that are connected for the operation under consideration. This deÞnition is
consistent with the deÞnition in 2.2.1.
The following notes may be useful for deÞning a suitable system representation:
a)
b)
c)
d)
e)
f)
g)
h)
i)
Representation of the ac system by an admittance deÞned by SCR is assumed to be relevant only to
transients (e.g., ac faults) of a few hundred milliseconds. (For more detailed study of some particular
characteristics, a more detailed representation may be required.)
As a consequence of a), the calculation of Y at fundamental frequency shall assume that synchronous
machine Þeld controls, transformer tap positions, and capacitor switching controls have no appreciable effect during the transient.
The reactance value of a synchronous machine is not constant, but effectively depends on the part of
the transient being studied and the method of supplying the Þeld. The apparent value varies between
subtransient and transient reactances (but not synchronous reactance). The effect of any errors in
assumptions about this will normally be reduced by Þxed ac system line and transformer reactances,
hence calculation based on subtransient reactances (as commonly used in short-circuit level calculation) will generally be sufÞciently accurate. However, in this simple representation it would be safer
to use the transient reactance for synchronous compensators connected in the station and for any
nearby synchronous machines.
The system damping is important for most phenomena, and therefore the impedance values corresponding to SCR and ESCR (and QESCR) should be expressed in polar form as magnitude and
angle. Thus, for example, for a system with SCR = 3 ÐÐ 80° the addition of 0.6 pu of capacitors plus
Þlters gives ESCR of about 2.4 ÐÐ 8°. (Please note that because SCR and ESCR are deÞned as
admittances [see 2.2.5.2], the angle should be negative as indicated.)
SCR (ESCR) values calculated at the ac terminals of the convertors may not be directly applicable in
special cases, such as where the convertor transformers have tertiaries connected to a synchronous
compensator or compensators. In this case, the physical position of the tertiary usually is between
line and valve windings such that there is a Þnite reactance between the Þlter bus and the tertiary terminals.
If the ac Þlters are connected to the tertiary winding of the convertor transformer, and if this winding
has a reactance value of almost zero (the tertiary is placed physically between line and valve windings), then the tertiary becomes the commutating bus. This means that the equivalent ac system
impedance is increased by the reactance of the line winding. Short-circuit ratios must be calculated
as if the line winding reactance forms part of the ac system.
Any capacitor banks associated with static var compensators (SVCs) should be lumped with other
capacitors on the busbar. If switched capacitor banks are used, then the maximum value of capacitors that may be connected during the operation to give lowest value of ESCR (or OESCR) for a particular system conÞguration should be used. The representation of continuously responding SVCs
requires careful consideration, as discussed in 2.2.1.5.
Short-circuit ratios deÞned in this subclause are not applicable for studies involving mechanical
shaft resonances of machines; such studies should use relevant system representation. The same
applies in general to all studies of slow phenomena associated with machines; e.g., inter-machine
and inter-system swinging, Þeld controls, and governors.
For some other studies (e.g., overvoltages and recovery from faults), it is important to represent the
convertor transformer saturation properties and nearby loads accurately. This may also apply to
other large transformers close to the convertor stations.
Although SCR (ESCR) calculated as above would give a numerical deÞnition of the ac system admittance
(and impedance) represented by the Thevenin equivalent circuit, when comparing the results all relevant
convertor quantities must also be stated: commutating reactance Xc , delay angle a or commutation margin
(g), and the control strategy. As discussed in 2.2.1.4, QESCR takes most of these into account.
16
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It was noted in 2.2.5.1 that different computer programs may give different values of system impedance,
which may lead to small errors. The more direct method to obtain an equivalent system impedance value is
to make all system emfs zero, inject a current at the terminal of the convertor, and measure the resulting voltage. This is, in effect, what a network reduction program does. It should always be remembered that it is necessary to obtain the value of the system impedance as accurately as possible; the short-circuit MVA has no
direct relevance in the study of dc operation, although it is a convenient quantity to use in discussion.
2.2.5.3 Load representation
It was pointed out in 2.2.5.1 that load representation is important. For example, induction motors add to the
emf of the system, but they do collapse at low ac voltage. A large number of induction motors in the vicinity
of the inverter may have considerable effect on the performance. It is recommended that users of both inhouse and externally sourced computer programs scrutinize how loads are represented in assessing the validity of SCR calculations. Loads should be represented using the best knowledge available. In the absence of
load data, it is suggested that load characteristics should be estimated rather than completely omitted. The
ac/dc system behavior is inßuenced by load characteristics, and the omission of load representation may give
misleading and possibly overly pessimistic results. For example, loads may contribute substantial damping
to transient disturbances, and possibly be the source of additional short-circuit MVA.
2.2.6 Application of synchronous compensators
Synchronous compensators have been used to strengthen the ac system at the inverter end in a number of dc
schemes. The cost and maintenance requirements of synchronous compensators may restrict their application to special situations.
In addition to the reduction of the system impedance, both at fundamental and harmonic frequencies, the
synchronous compensators have the following beneÞcial characteristics:
a)
b)
c)
They can supply both positive and negative continuously variable reactive power, which in most
cases eliminates the need for frequent shunt capacitor switching.
They tend to increase the natural resonant frequency between the Þlters and the ac system.
They are able to provide an increase of reactive power on reduction of ac busbar voltage, in contrast
with var reduction when supplied by shunt capacitors.
The application of synchronous compensators at schemes like Nelson River (Manitoba, Canada) and Itaipu
(Brazil) has changed the system from being a very low SCR system to a low SCR system as deÞned in 2.2.4.
A requirement for dimensioning the synchronous compensator in these schemes was the need to limit the
fundamental component of the temporary overvoltages to values lower than 1.4 pu. From the second table in
2.4, it can be seen that the operation at the CSCR corresponds to TOVfc of 1.4 pu (see also 3.1). It should be
noted that the reduction of the system impedance, by addition of synchronous compensators, to reduce TOV
has at the same time resulted in bringing the operating point, and therefore the operating direct current, to a
smaller value than IMAP .
2.2.7 Control of ac voltage by variable static equipment
The consequence of ac/dc interaction, when the ac system impedance is high, is evidenced by large ac voltage variations. Very fast and continuous ac voltage control would effectively strengthen the system.
The application of MO gapless surge arresters has contributed to the possibility of limiting TOV to required
values without the need to use SCs.
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2.2.7.1 The application of TCR and SR static var compensators
A fast TCR or SR static var compensator can be used to keep the terminal ac voltage constant within the
required range. The compensator var absorption must be continuously variable within its prescribed range.
In practice, the size (var range) of the TCR or SR has to be limited on economic grounds. These compensators lose control at very low ac voltage and may have limited overload range. The operating range is usually
increased by the use of thyristor-switched capacitors (TSCs) and/or mechanically switched capacitors to
keep the TCR or SR within its designed range.
Usually, a voltage/current or voltage/var characteristic of the TCR or SR is designed with a slope to suit the
ac system, usually 3Ð5% on the SVC rating. The equivalent system impedance is determined by the addition
of this slope reactance in parallel with the ac system impedance. However, as discussed in 2.2.1.5, the effect
of a TCR or SR is not included in the deÞnition of SCR but has to be considered for each separate scheme.
2.2.7.2 The application of the inverter with variable g
The reactive power consumption of the inverter can be varied by operation with different values of the commutation margin angle g (see Annex A of Part I).
Highgate and Virginia Smith (Sidney) convertors in the United States and McNeill in Alberta, Canada, are
examples of schemes that are designed to operate with very low SCR systems, and TOV is controlled by a
combination of MO arresters, convertor control action, and subsequent mechanical switching of capacitors/
Þlters. In the case of the McNeill station, the effective system impedance is increased by the line winding of
the convertor transformer [see 2.2.5.2, item c).]
If g is varied in response to ac voltage variation, the inverter can be designed to act as a TCR in a limited
range of conditions. As the dc transmission voltage depends on the value of g, during steady-state conditions
the convertor transformer tap-changer and mechanically or thyristor switched capacitors are used to keep g
near its nominal value. These matters are further discussed in Clauses 3 and 4.
2.2.8 Multiconvertor systems
General guidelines have to be considered with caution while studying a system, because a particular system
has to be studied in detail commensurate with its complexity.
Practical experience with, and the background investigations of, multiconvertor systems are not as widespread as that for more conventional two-terminal schemes. For this reason, the comments in this subclause
are kept in very general terms.
2.2.8.1 Multi-infeed systems
Multi-infeed inverters connected to the same busbar or being electrically close can be divided into two categories:
a)
b)
18
All inverters are controlled by one master controller, which shares the duty evenly among the separate inverters. In this case, the ac system impedance should be referred to the total dc power. The
short-circuit ratios should be calculated as if this were one large inverter. However, it should be
noted that even when only one master controller is used, the recovery of individual inverters can be
staggered with the effect being as if each inverter is recovering against a stronger system.
Two (or more) inverters are operated separately. As an example, suppose inverter A is at constant
power, and inverter B is at constant power but with power modulation. In most respects, the various
phenomena would be as if the system consisted of one large inverter. However, the demand for
power increase from the inverter B will respond as if short-circuit ratios are referred only to its own
power, but Qc in the formula must include all capacitors used with both inverters.
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2.2.8.2 RectiÞerÐinverter system
There are regions where convertors of two or more different dc schemes of comparable ratings are located
electrically close to each other. If one convertor is operating as an inverter while a neighboring convertor acts
as a rectiÞer, it can be viewed that the power infeed from the inverter of one dc scheme is totally or partially
taken away by the rectiÞer of another dc scheme, as shown in Figure 2-8. The situation is not dissimilar from
multi-infeed systems (2.2.8.1). To the Þrst approximation, the reactive power consumption of the rectiÞer
and the inverter are similar. Therefore, for most phenomena, the SCRs should be calculated by reference to
the total power P of rectiÞer plus inverter.
If the common ac system voltage suddenly reduces with or without ac system impedance increase, the rectiÞer will consume more reactive power and both dc currents will increase to maintain dc power which would
further increase reactive power consumption.
For the remote inverter, regarding any effects due to its ac system changes or power changes, its short-circuit
ratio should be referred only to its own power.
2.2.8.3 Multiterminal schemes
Each inverter SCR should be calculated with reference only to its own power for all phenomena, except
when considering recovery from faults. The dc peak current due to faults and commutation failures will
depend on the combined rating of the rectiÞers. This fact will lead to a risk of consequential commutation
failures, because the recovery will be carried out at this higher dc overcurrent compared to what would be
expected based on the inverter rating.
2.2.8.4 Two independent dc schemes operating in the same ac system
Two independent convertors may be connected to two different parts of the same ac system. To make two
inverters independent of each other, the ac impedance between them should have a high value. If two inverters are interconnected by a high-impedance ac line, they will be more independent of each other than if they
are further away from each other geographically but connected by strong ac lines. A low-impedance ac interconnection may lead to more interactions between the two inverters than if they were interconnected by a
ÒweakÓ ac link. An ac system fault anywhere on the ÒstrongÓ ac system will affect, more or less similarly, the
inverters connected to it and will approach conditions described in 2.2.8.1.
2.2.9 DC link in parallel with an ac line
The effect of an arrangement such as is illustrated in Figure 2-9 is not immediately obvious, and it is advisable to carry out studies with full representation rather than rely on SCRs. The following comments may
serve as general guidelines.
Figure 2-8ÑA rectiÞer and inverter connected at the same location
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Figure 2-9ÑAc and dc operating in parallel
2.2.9.1 Power transfer limits
In Clause 3 it is stated that values of MAP can be calculated for point-to-point schemes initially for the
receiving terminal under the assumption that the sending terminal will not impose a limitation, particularly
as the rectiÞer station can be designed, if that is desirable, not to impose a power limitation. However, for the
system shown in Figure 2-9, the following cases will indicate the position:
a)
b)
c)
d)
High SCR rectiÞer-end ac system (low ZR) and high-impedance parallel ac path (high ZP).
In this case, the rectiÞer loading will have negligible effect on the ac voltage at A, and the rectiÞer
will not impose a limitation as for normal point-to-point transmission. Furthermore, the inverter-end
ac system will beneÞt from the ac parallel line, and the impedance to calculate the SCR at B would
be equal to ZI in parallel with ZP + ZR .
Low and very low SCR ac system at rectiÞer end (high ZR) and low impedance parallel path (low
ZP).
In this case, the rectiÞer loading will inßuence the voltage at A, and due to the low ZP , the voltage at
B will be affected by both inverter and rectiÞer loading. Thus, the two convertors will behave in a
manner approaching the case of being connected to the same ac busbars. The use of SCR is not recommended in this case and full representation is preferred.
Low and very low SCR ac system at rectiÞer end (high ZR) and high impedance parallel ac path
(high ZP).
In this case, the rectiÞer loading may be limited by the low SCR sending-end system. The high ZP
will tend to decouple the two ac systems, but again, the use of SCR is not recommended and full representation is preferred.
For the fourth combination of high SCR rectiÞer end system (low ZR) and low impedance parallel ac
path (low ZP), the inverter end system is unlikely to have low or very low SCR.
2.2.9.2 Temporary overvoltages
Direct-current load rejection affects both the rectiÞer and the inverter, and therefore similar arguments apply
as in 2.2.9.1.
2.2.9.3 Recovery from faults
The inverter recovers against a system impedance, and therefore it will always beneÞt from a reduced
impedance.
2.2.9.4 Resonances
This case is similar to 2.2.9.3.
20
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2.2.10 General comments
It has been pointed out that the use of SCRs for estimating scheme performance should be made with caution. This is true in particular if the system departs from the standard point-to-point scheme. The more complex the scheme, the greater the need for full representation of the system.
When studying or designing a scheme, the ac system representation has to be as accurate and comprehensive
as required by a particular study. It must be stressed that it is often required to assume the possibility of a
particular ac/dc interaction in order to set up the simulator correctly or use a digital program. For example, in
a number of schemes no studies were carried out during planning or design stages that would have looked
for second harmonic or subsynchronous interactions and instabilities or resonances, and yet these effects
were experienced in service. One purpose of this guide is to draw attention to possible ac/dc interactions so
that correct studies can be carried out at appropriate times.
The effects of dc operation and mal-operation at fundamental frequency with a balanced ac system can be
simulated accurately using load ßow, transient stability, and other digital programs. The operating conditions
with distorted and/or unbalanced ac systems are studied by the use of dc simulators and electromagnetic
transients program (EMTP)-type programs.
2.3 Inadequate and zero mechanical inertia
2.3.1 Inertia constants
Turbine generators in an ac system represent a large rotating mass. Their inertia ensures that an ac system
does not collapse due to system faults. During a fault, a balance of power between load consumption and
generation is not maintained. The mechanical inertia of a turbine generator set ensures that its speed, and
therefore the frequency of the system (except for some oscillation), has not changed substantially.
A typical steam turbine generator set may have an inertia constant H of 5 s based on the generator MVA rating. Assume that a generator operates at 0.9 power factor, so that the inertia constant Hp based on its MW
rating is
5
H p = ------- = 5.55 s
0.9
Assuming that 2/3 of the power of an ac system is supplied by dc, then the inertia of the system referred to
dc power would correspond to
5.55
H dc = ---------- = 2.77 s, based on dc infeed
2
As is shown in the next subclause, an Hdc of 2.77 is usually adequate for satisfactory operation. It follows
that the dc infeed must represent a very large proportion of the system power supply, before steps need to be
taken to increase the inertia by addition of a synchronous compensator.
2.3.2 Infeed into a system without any generation
2.3.2.1 Calculation of frequency change
If all the power is brought into a system by dc (i.e., if there is no local generator), then that system will have
no mechanical inertia (apart from the inertia of motor loads, which can initially be neglected). The inverters
presently used in dc are line-commutated; i.e., they rely for their operation on the ac system providing adequate
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sinusoidal voltage to achieve the commutation process. Therefore, a dc inverter supplying an Òisland systemÓ
must be provided with a synchronous compensator having inertia adequate to maintain the frequency and voltage at an acceptable level during system faults.
The relationship between change of machine frequency (df), mechanical power input (Pm), and electrical
power output (Pe) for small changes of frequency can be represented by
( P m Ð P c ) ´ f o ´ dt
df = ---------------------------------------------2H
(4)
Where fo is the system nominal frequency and H is the conventional inertia constant of the machine
expressed in MWás/MVA of machine capacity, and Pm and Pe are in per unit of machine MVA rating.
If the inertia constant is converted to the base of dc power, it gives an effective inertia constant, Hdc.
MVAratingofthemachine
H dc = H × -------------------------------------------------------------MWratingofthedcsystem
(5)
giving from Equation (4)
p ´ dt ´ f
df = --------------------------o
2H dc
(6)
Where p is the per unit machine accelerating power (Pm Ð Pc) to the base of rated dc power.
It can therefore be seen that Hdc gives a measure of the inertial weakness of the system by relating the
change of machine speed to the temporary energy imbalance (p á dt) imposed by any given disturbance.
Temporary reduction of the power infeed by dc may be caused by the following typical events:
a)
b)
c)
A commutation failure lasting some 100 ms
A fault in the sending ac system or in the receiving system that may last up to some eight cycles,
depending on the backup breaker setting
A dc line fault, which may be cleared by dc controls in 100Ð200 ms
From Equation (6)
p ´ dt ´ f
H dc = --------------------------o
2df
(7)
For a loss of power for, say, 200 ms, to allow for the breaker clearance time and for the fact that the dc power
would not instantly recover to its rated level, it can be calculated from Equation (7) that Hdc to limit the frequency reduction to be, for example, 5%, will be equal to 2 s. It should be stressed that these values give
only an approximate indication of the requirements.
Zero-inertia systems are further discussed in Clause 9.
2.3.2.2 Forced commutation
Feeding into a system without any generation of its own and without synchronous compensators is not possible with conventional, line-commutated inverters, but Òforced commutationÓ is required and convertor circuits have been proposed. However, such schemes have not as yet been considered for actual projects.
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
2.3.2.3 Gate turn-off thyristors (GTOs)
Inverters using gate turn-off thyristors (GTOs), or similar devices, supplying power into a Òdead loadÓ have
been used in industrial applications. However, so far, the application of these devices to dc transmission has
not proved economical, but the promise is there.
2.4 Numerical examples of CSCRs and TOVfc values
CSCRs and the fundamental component of the temporary overvoltage for an assumed impedance angle of
f = 80° have been calculated for six cases of inverter operation with different equipment characteristics. For
cases A, B, C, and D, it is assumed that Qc = Qd . For cases E and F, shunt capacitors are sized to provide
some net vars to the ac system at the rated condition.
Case
Commutating
reactance Xc %
Commutation
margin g (minimum)
Qd
Qc
A
B
C
D
E
F
12%
15%
20%
20%
12.6%
20%
18°
18°
18°
20°
17°
18°
0.5 P
0.54 P
0.6 P
0.63 P
0.5 P
0.6 P
0.5 P
0.54 P
0.6 P
0.63 P
0.875 P
0.875 P
Case
CSCR
A
B
C
D
E
F
1.87
2.01
2.2
2.25
2.24
2.47
CESCR*
Ð80°
Ð80°
Ð80°
Ð80°
Ð80°
Ð80°
1.37
1.47
1.6
1.62
1.37
1.60
Ð76.4°
Ð76.4°
Ð76.3°
Ð76.1°
Ð73.7°
Ð74.5°
CQESCR
TOVfcà
0.91
0.95
1.0
0.99
0.91
1.0
1.43
1.42
1.40
1.41
1.39
1.39
NOTEÑFor these examples, commutating reactance = convertor transformer leakage reactance.
* Calculated by the equations in 2.5.
Calculated from CESCR by adding the corresponding value of Qc in pu of Pd.
à Calculated by Equation (27), which gives a theoretical value, as it does not include the transformer saturation effect.
The maximum difference between the cases are as follows (see also Figure 2-10):
CSCR
CESCR
CQESCR
TOV
32.0%
17%
10%
1.8%
It is clear that the value of MAP depends on the system impedance, shunt capacitor Mvar Qc, and the reactive consumption of the inverter Qd. For this reason, the variation in CSCR is the largest. CESCR takes into
account the inßuence of Qc and the difference in CESCRs is greatly reduced. CQSCR takes into account the
value of both Qc and Qd. If QESCR is between 0.9 and 1.0, the operation is at or near MAP.
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It is also interesting to note that the value calculated for TOV for all cases is around 1.4 pu. It can be shown
that if the operation at MAP (i.e., at CSCR) is at unity power factor, then TOVfc (for complete load rejection)
is k á 21/2 of the terminal ac voltage at MAP. The factor k has a value close to unity for typical ac system data
(see also 3.1).
Even if the normal operation is at a g larger than minimum, CSCR should be calculated for g minimum, as
that would represent the maximum obtainable power (MPC). However, TOV should be calculated using the
normal (operating) g, as the rated Qd (not the one corresponding to minimum g) will be rejected by the convertor in case of a fault.
Critical Ratios
CSCR, CESCR, and CQESCR are plotted on Figure 2-10 against the commutating reactance Xc for values of
g = 15° and 20°, F = 70° and 90° and for Qc /Qd = 1.0 and 1.5.
2.6
2.4
2.2
2.0
1.8
1.6
1.4
1.2
1.0
0.8
10
= 90¡
g = 20¡
Q c /Q d = 1.5
CSCR Range
= 70¡
g = 15¡
Q c /Q d = 1
CESCR Range
CQESCR Range
12
14
16
18
Commutation Reactance %
20
Figure 2-10ÑSensitivity of CSCRs
2.5 Calculation of CSCRs
If the starting conditions (Pd = 1.0, UL = 1.0, Id = 1.0) coincide with the MAP of MPC (e.g., Figure 2-3 for
SCR = 2), the corresponding SCR is termed Òcritical.Ó
For a simpliÞed system representation (Figure 2-1), the critical ac system impedance can be calculated from
the following equation:
1
CESCR = ------2- sin fP d tan ( g + u ) Ð Q d +
UL
Pd
------------------------cos ( g + u )
2
2
Ð cos f ( P d tan ( g + u ) Ð Q d )
2
(8)
It should be noted that shunt capacitors must be assumed to be connected.
The value of CESCR is little affected by the system damping in the range of 70°Ð90°, and if system damping
is neglected (f = 90° approximately), a good approximation is obtained by the following:
1
CESCR = ------2 [ Ð Q d + P d cotan 1/2 ( 90° Ð g Ð u ) ]
U
UL
Qd
24
(9)
is convertor bus ac voltage per unit,
is reactive power consumed by the inverter (per unit) [calculated from Equation (A.7), (A.11), or
(A.13) in Annex A of Part I],
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Pd
g
u
f
IEEE
Std 1204-1997
is active power supplied by the inverter to the ac system (per unit),
is extinction angle of the inverter,
is overlap angle of the inverter [calculated from Equation (A.9) in Annex A of Part I],
is angle of ac system impedance.
CSCR can be calculated by adding Qc to Equation (9).
CESCR can also be calculated by considering the effect on the ac voltage of small var changes at the convertor ac busbars. The magnitude of this effect can be judged by the voltage stability factor.
The voltage stability factor (VSF) is deÞned as the incremental ac voltage variation, dUL, due to a small
reactive power (dQ) injected into the commutation busbar for a given power level, i.e.,
dU
VSF = ---------LdQ
(10)
This index can be used for calculating the critical ratios for large systems using digital computer programs.
VSF is a more general factor than CSCR and CESCR, and is also used in the study of ac systems. VSF also
permits an approximate evaluation of the system dynamic behavior under small perturbations from a voltage
oscillation point of view. VSF is plotted against ESCR in Figure 2-11. This Þgure assumes operation in the
constant g mode. A positive VSF indicates that the dc would operate, in constant g mode, at currents smaller
than IMAP . A negative VSF indicates that the system would operate, in constant g mode, at a dc current
greater than IMAP. The transition point of VSF as dc current changes gives the same criterion as the MAP
concept and Equation (1) applies identically to both. It should be noted that a negative VSF indicates that the
constant power control mode with constant g would be unstable. However, in constant current control with
constant g, VSF has a positive value.
CSCRs can be calculated with adequate accuracy for planning considerations using the following simple
equations derived from Equation (3):
CESCR = CQESCR ( 1 + Q d )
(11)
CSCR = CQESCR ( ( 1 + Q d ) + Q c )
(12)
and
where
Qd and Qc are in per unit of Pd .
From Figure 2-12, approximate values of CQESCR and Qd can be obtained, and Qc can be selected according to the desired reactive compensation.
Example 1, for average value of the commutating reactance Xc = 15%: From Figure 2-12, CQESCR = 0.95;
for g = 15°, Qd = 0.54; and for Qc = Qd, the following value for CSCR is obtained from Equation (3):
CSCR = 0.95 * (1 + 0.54) + 0.54 = 2.0
Using the correct Equation (1) for Xc = 15%, g =18°, Qc = Qd, F = 80°, CSCR = 2.0.
Using the correct Equation (1) for Xc = 15%, g = 20°, Qc = Qd, F = 70°, CSCR = 2.04.
Using Equation (12) and Figure 2-12, we also get CSCR = 2.04.
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VSP
VSF
dP/dI
d
dP/dId
Constant g control
(a) VSF (I d control by rectifier)
(b) VSF (P d control by rectifier)
d P/ dId
(c) dP/dI
d
(a)
(b)
2.0
CESCR
(b) 1.0
(c)
ESCR
3.0
X c = 0.2 pu, g = 18¡
Q c = Q d = 0.6 Pdn
Figure 2-11ÑVSF and dP/dId as a function
of the ESCR
at nominal operating conditions
Figure
2.10
and unity power factor
VSF and dP/dId as a Function of the Effective Short
Circuit Ratio (ESCR) at Nominal Operating Conditions
CQESCR
1.0
0.8
Q d in
per unit
of Pd
0.6 g = 21¡
g = 18¡
0.4
g = 15¡
10
12
14
16
18
Xc Commutating Reactance (%)
20
Figure 2-12ÑCQESCR and Qd as a function of Xc
Figure 2.12
26
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Example 2, for Xc = 20%: From Figure 2-12, CQSCR = 1.0; and for g = 20°, Qd = 0.64, for Qc = 1.5Qd:
CSCR = 1.0 * (1 + 0.64) + 0.96 = 2.6
Using the correct formula for Xc = 20%, g = 20°, F = 70°, Qc = 1.5Qd , CSCR = 2.56.
Using the correct formula for Xc = 20%, g = 15°, F = 70°, Qc = 1.5Qd , CSCR = 2.4.
Using Equation (12) and Figure 2-12, we also get CSCR = 2.04.
2.6 Numerical examples of power reduction due to ac system impedance increase
and ac voltage reduction
As discussed in 2.2.4.5, power reduction due to a reduction of the terminal voltage is greater if the system
impedance is increased at the same time.
Consider the case represented in Figure 2.6a and Figure 2-6b.
Initial conditions at SCR = 3.
System emf
0.998
Id
1.0
UL
1.0
Ud
1.0
g
Pd
1.0
SCR
18°
3
Condition after the line trip, increases Zs by 1/3.
a)
0.998
1.0
0.93
0.92
0.92
18°
2
0.998
1.1
0.84
0.81
0.90
18°
2
0.998
0.96
0.97
0.96
0.93 (MAP)
18°
2
b)
Condition after system emf reduces to give UL = 0.93 at SCR = 3.
0.947
1.0
0.93
0.92
0.92
18°
3
0.947
1.1
0.89
0.87
0.96
18°
3
0.947
1.25
0.82
0.78
0.98(MAP)
18°
3
It can be seen that conditions immediately after system change and before dc current changes (i.e., at
Id = 1.0) are identical for the two cases, but in case a), IMAP is at 0.96 pu, and in case b), it is at 1.25 pu of Id .
Operation at a current limit of, say 1.1 pu, would result in a power of 0.9 in case a) and 0.96 in case b).
A demand to maintain rated power (without, say, capacitor switching) at a speciÞed minimum SCR for a
sudden system change may not justify the increase in the extra cost of the convertor equipment and the extra
cost of losses. This is especially true if the particular system change is an uncommon event.
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2.7 AC/DC system strengthÑsummary tables
2.7.1 Power transfer and TOV
MAP(2)
TOVfc (theoretical)
High SCR systems
SCR > 3, ESCR > 2.5
PMAP > 1.1
1.25 < TOVfc
Low SCR systems
3 > SCR > 2, 2.5 > ESCR > 1.5
PMAP > 1.1
1.25 < TOVfc < 1.4
Very low SCR systems
2 > SCR, 1.5 > ESCR
(3)
TOVfc > 1.4
2.7.2 CSCRs
CSCR = 2
CESCR = 1.47
CQESCR = 0.95
NOTES to 2.7.1 and 2.7.2:
1ÑThe Þgures in 2.7.1 and 2.7.2 are based on assumed typical values of Xc (15%), gmin (18°), and Qd = Qc = 0.54 á PdN.
If Xc and gmin have higher values resulting in larger Qd, then the theoretical division between high and low SCR systems
would be at an SCR value higher than 3, and the division between low SCR and very low SCR systems would be at an
SCR value higher than 2.
Similarly, values of ESCR, CSCR, or CESCR would have correspondingly higher values.
CQESCR would still have a value near unity; see Figure 2-10.
2ÑPMAP represents the maximum power immediately available starting from nominal (rated) conditions (Pd, UL, and
Id are all at one per unit, and gmin = const), without the use of fast ac voltage control.
3ÑThe additional power available immediately, starting from nominal rated conditions, depends on the equipment
design; i.e., the value of g, or on the available range of TCR and SR.
2.7.3 Inadequate inertia systems
To avoid frequency reduction by more than 5% (i.e., 2.5 Hz for 50 Hz systems or 3 Hz for 60 Hz systems)
due to a system fault, the effective dc inertia constant, HDC, should be greater than 2 s.
3. DC power transfer limits
3.1 Description of phenomena
Considering the fundamental components of ac currents and voltages, a power system may exhibit two
major types of instabilities:
a)
b)
28
Phase angle instability and
Voltage instability
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The Þrst of these is characterized by the fact that, after a disturbance, a generator or a group of generators
loses synchronism with the rest of the system and line trips are executed by out-of-step relays or some other
protection. The reason for the system to separate could either be that no new operating point exists (steadystate instability), or that the system cannot settle down to the new equilibrium point due to the kinetic energy
injected into the rotors of the generators as a consequence of the fault (transient instability). The system
could also become unstable due to inadequate damping. The time scale for this instability is typically in the
region of a few to ten seconds. These matters are discussed further in Clause 7.
The voltage instability is characterized by the fact that the voltage at a certain bus or in a certain region of the
network progressively decreases. (Usually it collapses, and this type of instability is often called voltage collapse.) The generator pole angles do not necessarily change signiÞcantly. (This is at least true during the initial stages of the breakdown. The voltage instability may cause protection to act, which could cause the
system to become phase-angle unstable). The time scale for this instability may vary substantially, depending on different characteristics of the system. If tap-changers are involved, the process can extend over several minutes. The instability could develop much faster if, for example, tripping of a line or of a shunt
capacitor bank results in sudden lack of voltage support, or some fast controllable devices play decisive roles
in the dynamics of the system.
Extensive work is going on at present concerning the voltage collapse phenomenon as a consequence of a
number of large breakdowns and disturbances that occurred in recent years and are believed to have been
caused by voltage instabilities. No generally accepted method of analysis or description of the phenomenon
exists for a generic system, but some general characteristics could be described by the following simple
model.
Consider a load supplied by a strong network via a transmission line, as in Figure 3-1. For a given load, there
exist in steady state two possible modes of operation: one with ÒhighÓ voltage and ÒlowÓ current, and one
with ÒlowÓ voltage and ÒhighÓ current. Normally, the Þrst of these two solutions is the desired one, since it
gives lower losses and exhibits other properties that are attractive. If the voltage at the sending end is kept
constant, curves as shown in Figure 3-2a are obtained for different power factors of the load. From these
curves the following important observations can be made:
Ñ
Ñ
There is a maximum possible load that can be supplied at a given power factor.
For a given load smaller than the maximum, two different operating points exist corresponding to
different voltage levels.
Z
US
Source
UL
P, Q.
Figure 3-1ÑSimpliÞed ac system representation
Furthermore, a simple analysis shows that
Ñ
Ñ
For operating points on the upper branch of the curve, dU/dQ > 0; and on the lower branch, dU/dQ < 0.
If Us is the voltage at the sending end it can be shown that dU/dUs > 0 for points on the upper branch,
whereas dU/dUs < 0 on the lower branch.
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The last two observations, together with the standard ways of controlling voltage in ac systems, lead to the
fact that points on the upper branch are called stable and those on the lower branch are called unstable. The
point corresponding to the maximum load is mathematically called a static bifurcation point. If a power
larger than this maximum is demanded by a load device, the system cannot converge to any of the solutions
that are given in Figure 3-2a. To predict the behavior of the system for such a case, the dynamic properties of
the system are needed, such as load characteristics, tap-changer control, and generator/motor dynamics.
Terminal Voltage
UL
1.0
A
Lag
P.f.= Lead
1.0
B
0.4
0.8 1.0 1.2
1.6
2.0
Power pu
Figure 3-2aÑTerminal voltage versus power for different load power factors
Consider the curve for unity power factor of Figure 3-2b for the case in which the small resistance of the ac
line is neglected. It can be shown that for such a case, the terminal voltage, UL, corresponding to the MAP, is
related to the sending end voltage by the following equation:
U
U L = ------s2
(13)
In the curves in Clause 2, dc power and ac terminal voltages are plotted as a function of dc current. From
these curves it is seen that the ac terminal voltage is a monotonic decreasing function of dc current, and consequently there is a unique relationship between the dc current and the ac terminal voltage. Therefore, it is
possible to plot the dc power as a function of the ac terminal voltage. Furthermore, if in such a plot the ac
terminal voltage is on the y-axis and the dc power on the x-axis, the well-known ac voltage/power curve
used in ac system analysis is obtained. Some of the curves shown as dc power versus dc current will be discussed below as ac voltage versus dc power.
The ac system impedance for Figure 3-2b was chosen to be equivalent to the system impedance of the
inverter operation curve for SCR = 2 (ESCR = 1.46) of Figure 2-3. The ac voltage/power curve corresponding to Figure 2-3 for SCR = 2 is almost identical to that of Figure 3-2b. The reason for this is that in
Figure 2-3, the power factor at PdN = 1.0 pu is unity.
AC voltage and power from Figure 3-3 for SCR = 4.5 and from Figure 3-4 for SCR = 3 are plotted in
Figure 3-2c. The main difference between the curves of Figure 3-2c and Figure 3-2a is that the former are
calculated to give one per unit ac voltage at one per unit dc power, and those of the latter are calculated to
30
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UL
1.4
A1
A2
MAP
A3
P
0
1.2
Figure 3-2bÑAC voltage/power curve (unity load power factor)
give one per unit ac voltage at zero power;
are differences in system impedances in the former
Fi also, there
3 2b
curves. However, curves corresponding to the operation of a dc convertor are the same as those of an ac load
having the same P and Q characteristics.
The third curve in Figure 3-2c corresponds to the curve for SCR = 2 of Figure 3-4. This curve is obtained by
tripping one of the two parallel ac lines to which the inverter was connected (Figure 2-4) when operating at
the point A of the curve for SCR = 3, as discussed in 2.2.4.2 and 3.2.2. It can be seen that the maximum
power (MAP) of the curve, corresponding to the new condition, is lower than the power before the disturbance at point A. The attempt of the convertor load to draw an increasing current, in order to maintain the
original power, would result in voltage collapse, as already discussed.
UL
SCR = 2.0
From Fig 3.4
1.4
1.2
A
1.0
SCR = 4.5
From Fig 3.3
0.8
0.6
SCR = 3.0
From Fig 3.4
0.2
0.4
0.6
0.8
1.0
1.2
P
d
1.4
Figure 3-2cÑAC voltageÑdc power curves
Figure 3 2c
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An important factor, which differs in the dc case as compared with the pure ac conÞguration, is the controllability of the dc convertor. As will be shown in this clause, unlike the general ac case, the convertors can be
controlled in such a way that voltage instability does not occur and that, moreover, the dc controls can further enhance the performance of the ac system. For these reasons, it is convenient to plot power against dc
current, the controlled quantity, rather than against the voltage, but the phenomena are considered the same.
X c = 0.15 pu, g = 18¡
Q c = Q d = 0.54¥Pdn at U L = 1.0 pu (Point A)
1.6
Pd or UL (pu)
1.4
ESCR = (2.46)
SCR = 3.0
1.2
1.0
MPC - 1
SCR = 4.5 (3.96)
SCR = 4.5
(3.96)
A
B
MPC -2
SCR = 3.0 (2.46)
0.8
0.6
0.4
Pd
UL
0.2
DC Power
AC Volts
0
0
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu)
Figure 3-3ÑAC/DC systemÑhigh SCR, sudden change of SCR from 4.5 to 3.0
3.2 Power limits of an inverter
3.2.1 Power limits of an inverter connected to a high SCR ac systemÑwith g constant
The operating point of an inverter connected to an ac system having a high SCR, will be well below MAP; in
Figure 3-3 an SCR = 4.5 has been assumed. In such cases, it is most economic to design the system so that
the operating point is on the MPC for g minimum. The operation at MPC is achieved while operating the
inverter at a constant commutation margin having minimum g value of, say, 15° (50 Hz), 18° (60 Hz). The dc
voltage is maintained close to its rated value by the inverter transformer tap-changer
Operation at MPC (minimum g) gives minimum cost due to the following factors:
Ñ
Ñ
Ñ
Ñ
Minimum reactive power consumption
Minimum ratings of valves, transformers, and shunt capacitors
Minimum generation of harmonic currents
Minimum losses
MPC can be suddenly reduced by a combination of the increase of the ac system impedance and of the
reduction of terminal ac bus voltage, possibly due to a line trip in the ac system. Such a reduction of MPC is
shown in Figure 3-3.
32
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The pre-disturbance operation is with a system having SCR = 4.5. The operating point A corresponds to Pd,
UL, Ud, and Id having the rated values of 1.0 pu. The commutating reactance is 15%, the inverter reactive
consumption QdN = 0.54 á PdN. The nominal rating of shunt capacitors (including Þlters), QcN, is Þxed and,
at UL = 1 pu, is equal to QdN. Operation is at minimum constant g.
If, following an ac line trip, as discussed in 2.2.4.1, while operating at point A, the system impedance is
increased by one-third corresponding to the sudden reduction of SCR from 4.5 to 3, the operation will be
according to MPC-2 of Figure 3-3.
MPC-2 is also a quasi-steady-state curve, but for the new ac system conditions.
Assuming constant-g control at the inverter, a decrease in the inverter ac voltage causes an immediate
decrease in dc voltage. Assuming for the present that the HVDC master control at the rectiÞer is for constant
power (which is not always the case), then it will increase dc current to maintain power at the set value,
unless the current-limit setting in the rectiÞer is reached. It is still assumed that AVRs, circuit breakers controlling shunt capacitors, etc., and on load tap-changes (OLTCs) have not operated, as they are slow compared to dc current controls. MAP-2 in this case is higher than the rated power PdN and the power has been
maintained at its predisturbance level, at the new operating point B.
For details of numerical values see 3.9.
3.2.2 Power limits of an inverter connected to a low SCR ac system with g constant
There are a number of schemes in service with SCR having an approximate value of three or lower, but
higher than SCR equal to two, with normal operating point at MPC with constant g at rated currents smaller
than IMAP (see 3.6.2). However, the operation is sufÞciently near MAP-1 that a sudden, but relatively moderate, change in the ac system voltage may result in a MAP-2 being lower than the rated power. This event is
illustrated in Figure 3-4. A similar event, as shown in Figure 3-3, has been assumed, except that the system
impedance prior to the line trip corresponds to SCR = 3, and after the line trip to SCR = 2. The required
power cannot be maintained, but the current limit imposed by the rectiÞer prevents the collapse of the system, despite the demand for higher power from the master controller.
The operating point B on MPC-2 will be in the region where dPd /dId is negative and stable operation would
not be achieved in power control mode, but stable operation continues in constant current control mode.
If the dc system is used to control ac frequency or to provide system damping, operation in the constant-current mode would not be acceptable except for a very brief period of time; e.g., while the fault is being
cleared. Also, for these changes in ac system conditions, the power level may drop quickly to a lower value
(determined by current limit) and also jump back to the original value if ac system conditions are suddenly
restored. For possible steps to be taken to enhance performance in such cases, see 3.6.
For details of numerical values, see 3.9.
3.2.3 Power limit of an inverter connected to a very low SCR ac system with variable g control
The operation at currents higher than IMAP corresponds to operation at a point on the lower branch of a curve
shown in Figure 3-2, which in ac transmission is considered the unstable part of the characteristics. In principle, it can be argued that it is the nature of the load that determines the stability. Assume that the load in
Figure 3-1 is a static impedance load. If the impedance of the ac supply line is high, and if the inductive
component of the load is high, the maximum power in Figure 3-2 would be relatively low and the operating
point may be at the lower ÒunstableÓ part of the curve. An inverter connected to a high-impedance ac line
operating at constant g in the region where dPd /dId is negative will be unstable if its controls demand an
increasing current to keep the power constant. But if the controls are arranged to keep the current constant,
stability can be achieved. However, any variation of ac voltage would directly cause variation of power that
would not be acceptable for most applications.
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
1.6
Pd or UL (pu)
1.4
X c = 0.15 pu, g = 18¡
Q c = Q d = 0.54¥Pdn at U L = 1.0 pu
SCR = 2.0
1.2
SCR = 3.0
1.0
MAP -1
A
B
C
0.8
MPC - 1
SCR = 3.0
MAP -2
0.6
0.4
0.2
0
Pd
UL
MPC - 2
SCR = 2.0
DC Power
AC Volts
I LIMIT
0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu)
Figure 3-4ÑAC/DC systemÑlow SCR power and ac voltage curves, sudden change of
SCR from 3.0 to 2.0
Figure 3.4
An alternative control strategy, used in a number of schemes, is to control the dc voltage through inverter
action by varying g. The rectiÞer performs the same duty as in the previous case of controlling the dc current
in order to achieve the desired power. An increase of g increases var consumption and a decrease of g reduces
the var consumption. Therefore, in order to be able to increase ac voltage, as well as to reduce it, the inverter
must be normally operating at a higher g than the minimum.
Consider the four power curves in Figure 3-5. Normal operation is at point A with g = 25°, curve MPC-1.
Commutating reactance Xc is 15%, as in the previous cases. The value of shunt capacitors is made equal to
Qd at g = 25° at UL = 1.0 pu. It should be noted that normal operation at currents smaller than 1.0 are not
practical due to the high voltage as explained in 2.2.3 and by Figure 2-3. For example, MAP-1 occurs at
IMAP = 0.75 pu, UL = 1.4 pu, and Ud = 1.5 pu. Therefore, for normal operation with ac systems having very
low SCR at dc currents higher than IMAP, the power transfer limit is lower than the power corresponding to
MAP. In the example in Figure 3-5, the maximum transmittable power, before ac system conditions are
changed, is obtained by reducing g to its minimum value. In this example, at the minimum g = 18°, the point
B is reached on MPC-2, which represents the maximum power that can be achieved from normal operating
conditions by increasing current. The straight line O-A-B is the line of constant dc voltage. It should be
noted that control of dc voltage, for operation with ac systems having very low SCRs, is not necessarily the
only control strategy for operation at Id > IMAP. Controlling other quantities, such as ac voltage, reactive
components of the inverter current, etc., could also be considered.
34
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
IEEE
Std 1204-1997
MPC-1 X c = 0.15 pu, Q c = Q d = 0.665 Pdn at
U L = 1.0 & g = 25¡ (Point A)
1.4
MPC - 1 (SCR = 1.5, g = 25¡)
MAP -1
MPC - 2 (SCR = 1.5, g = 18¡)
Power Pd (pu)
1.2
A
1.0
B
MPC - 3 (SCR = 1.3, g = 25¡)
C
0.8
MPC - 4 (SCR = 1.3, g = 18¡)
0.6
0.4
0.2
Constant
DC Voltage
Pd
UL
DC Power
AC Volts
0
0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu), ld
DC Current (pu), Id
Figure 3-5ÑAC/DC systemÑvery low SCR, sudden change of SCR from 1.5 to 1.3
Figure 3 5
Curve MPC-3 is obtained by assuming that an ac line has tripped, causing an increase in the system impedance by 13%. At Id = 1.0, before a change of g value, this would result in reductions of UL to 0.81 pu, Ud to
0.8 pu, and Pd to 0.8 pu, point C on MPC-3. However, g would instantly respond by reducing its value. In
this example, this would result in restoring the power to 1 pu, with UL = 0.95, gd = 1.0, and Id = 1.0, at minimum g = 18°; i.e., point A on MPC-4.
The variable g is maintained at its normal value, in the example considered at 25° by the inverter tap-changer
and by shunt capacitor switching. For example, if the condition of MPC-4 persisted, additional shunt capacitors would be switched in order to increase the ac voltage and allow g to return to a value near 25°. It must
be stressed that, as in the previous cases, the controls must be stable during the period before capacitor
switching in, for operation at g minimum in the current control mode (at dPd /dQ < 0).
The cost of the inverter designed for continuous operation at larger values of g will be higher compared to
the inverter designed for operation at minimum g for the following reasons:
a)
b)
c)
d)
Reactive power consumption will be greater.
Valves, transformers, and shunt capacitors will have higher ratings.
Generation of ac and dc harmonics will be higher.
Convertor terminal losses will be higher.
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The beneÞt of operating with variable g is the ability to operate stably in the power control mode, for the
design range of ac system variations, at dc currents larger than IMAP, with ac systems having very low SCRs.
A further beneÞt is that, due to normal operation at g larger than minimum, the probability of commutation
failures would be reduced.
For details of numerical values, see 3.9.
3.2.4 Results from a transient stability program
As discussed in the previous subclauses, to determine the power limits of an inverter (or of a rectiÞer)
Òquasi-steady-stateÓ power curves are used; i.e., each subsequent point is calculated by steady-state equations. These calculations are conveniently done by hand or, as in most cases of curves in this guide, by digital load-ßow programs having adequate dc link representation. The statement that these quasi-steady-state
curves give a good indication of dynamic performances was veriÞed by using a transient stability program.
The conditions of an inverter having data as used in the case of the power curve in Figure 3-4 for SCR = 3
has been used. The SCR of the rectiÞer was set to a very high value in order not to represent a limitation to
the inverter performance. Results are shown in Figure 3-6. It should be noted that the particular controls used
with this program allowed normal g to reduce from 18° to an absolute minimum of 15°. Temporary reduction
of g allows a higher (short time) overload or maintenance of required power for a slightly greater voltage
depression, at a risk of higher commutation failure probability. The power order was increased by 10% at
time = 0.04 s. The current limit was set to a value of just over 1.3 pu in order to show the power increase to
MAP and its subsequent reduction, despite the current increase. Soon after 0.1 s the current is reduced in
response to ac voltage reduction, and so reduces the inverter var consumption. This is one of the methods
used in practice to avoid ac voltage collapse. The analysis of the values of Id, Ud, Pd, and g indicates that
these quantities are consistent with values achieved for Figure 3-4 for SCR = 3.
3.3 Power limits of a dc link
3.3.1 Introduction
In the preceding subclauses, the limits that an inverter may impose on the value of power transmitted were
considered under the assumption that the rectiÞer operation will not be responsible for a lower limit. However, the rectiÞer is subject to the same limitations as the inverter; at increasing dc current the voltage will be
reducing and the amount of control in hand depends on the value of a in normal operation. In this subclause,
an example is given that takes into account both ends of the dc link. It has been assumed that the scheme is
bidirectional and that the two ac systems have different values of SCRs. Either end may function as an
inverter, but with differing operating strategies. Normal operation at g = 19° (with absolute limit at g = 15°)
was assumed for the ac system having a low SCR value (system X) and a variable g strategy was assumed to
control dc voltage for the other end, which has a very low SCR value (system Y). The effect of a 5% ac voltage reduction on power transfer was calculated.
3.3.2 Example data
ESCR
Xc
System X
2.75
15%
System Y
1.0
14%
(f was assumed to be 90°, as the resistive component has only a small effect on power calculation.)
Table 3-1 gives initial conditions. Power is assumed positive for the system X to system Y direction and it is
assumed negative (marked with a minus sign), for the opposite direction.
36
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Power
LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
IEEE
Std 1204-1997
1.0
0.8
0.6
0.4
0.2
DC Current
1.4
1.3
1.2
1.1
1.0
0.9
DC Voltage
0.04
1.0
0.8
0.6
0.4
0.2
0.06
0.08
Time (seconds)
0.10
AC Voltage
1.0
0.96
Inverter
0.92
Reactive Power
in per-unit of Pd
0.88
0.9
0.7
Inverter
0.54
0.4
45
Degrees
35
g for Inverter
25
18
10
5
a for Rectifier
0.04
0.06
0.08
Time (seconds)
0.10
Figure 3.6
Results of Transient Stability Program for a 10%
Increase of Power Order Applies at 0 04 Seconds
Figure 3-6ÑResults of transient stability program for a 10% increase of power order,
applies at 0.04 s, X = 0.15%, Qc = Qd = 0.54Pd , g = 18° at UL = 1.0
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Table 3-1ÑInitial conditions
DC system data
System emf
Case
Udc pu
Id pu
a (rectifier)
g (inverter)
X
Y
A
1
1
12°
25°
1.047
1.169
*B
Ð1
1
12°
19°
1.047
1.101
*Power
from Y to X.
3.3.3 Application of the disturbance
Voltage changes are speciÞed as Òchanges of 5% of the nominal bus voltage.Ó It is therefore assumed here
that the observed voltage change at the disturbed busbar is 5%, whatever the prime cause (e.g., a remote fault
or loss of a line with negligible change in the value of the system impedance).
Table 3-2 summarizes the cases studied.
Table 3-2ÑSummary of cases studied
Case
ref.
Power
flow
System voltage
depressed 5% at
A1
XÐY
X
A2
XÐY
Y
B1
YÐX
X
B2
YÐX
Y
3.3.4 Calculated solutions
Table 3-3 gives the calculated solutions. These are for the conditions after the convertor controls have settled
(i.e., after about 100 ms) but before tap-changers or capacitors have switched. The Òremote busbarÓ is the
convertor busbar not subjected to the initial voltage depression.
Table 3-3ÑCalculated solutions after voltage depression
Case
Power pu
AC voltage
on the remote busbar
Udc pu
Id pu
a (rectifier)
g (inverter)
A1
0.970
0.990
0.970
1
3°
26.7°
A2
1
1
1
1
12°
18.4°
*B
1
0.969
0.969
Ð0.962
1.039
10.5°
15°
*B2
0.972
0.997
Ð0.972
1
3°
21.9°
*Power
from Y to X.
38
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IEEE
Std 1204-1997
3.3.5 Comments on individual cases
For cases A1 and B2, the rectiÞer a reaches its minimum of 3° and the inverter takes over control of current
(and power) by increasing its g, which increases its reactive power consumptionÑhence reducing its ac busbar voltage.
For case B1, a combination of the reduction of g to 15° and the increase of dc current to 1.039 pu successfully restores power to 1.0 pu.
Power is reduced by up to 3% for cases A1 and B2; otherwise, power control is maintained (except for a brief
dip until the master control takes effect). This is because the master power control output (current order)
reaches the sliding current limit (refer to 3.6.2.1), which, for a power order of 1 pu, limits dc current to 1.05
pu if the rectiÞer is still in control or to 1 pu if the inverter is in control.
The ac voltage on the ÒremoteÓ busbar is only slightly depressed in all cases, with a maximum of 3.1%
(case B1).
The results in Table 3-3 are to some extent a compromise, because they depend on the values used for the
current limits (1.05 and 1.0 as described above). For example, an increase in current limit by .05 pu for case
A1 would cause the power to be maintained at 1 pu (instead of 0.97 pu) but with a larger reduction of remote
ac voltageÑby 3.2% instead of 1%. In other cases, an increase in current limit would actually reduce power,
with a further voltage depression, and would therefore be pointless.
In practice, the capacitor switching and tap-changer control would restore the desired conditions.
3.3.6 RectiÞer connected to a very low SCR ac system
The main consideration in this guide is given to the conditions at the inverter of a dc link terminating at locations having low short-circuit capacity. However, particular attention must be given to the case in which the
rectiÞer ac/dc system has a very low SCR.
In ac/dc systems having a very low SCR, it is essential to have fast control of the voltage. If the dc link itself
is used to provide this fast control, the inverter is the voltage-controlling convertor. One common method is
to control for constant dc voltage, which indirectly exerts a control on the ac voltage. In back-to-back systems, if the ac voltage at either end rises to a predetermined value, an ac voltage loop takes over to control ac
voltage directly, operating through the inverter control system.
If there is a dc line between the rectiÞer and the inverter and the rectiÞer ac/dc system has a high SCR value
and the inverter has a low or very low SCR value, the system will operate well, as the inverter controls dc
and ac voltages local to the very low ac/dc system. However, if the rectiÞer ac/dc system has a very low SCR
value, the inverter will not be very effective in quickly controlling the dc voltage at the rectiÞer end, and
therefore its ac voltage (due to the inductance and the capacitance of the dc line), even if the telecommunication were to be very fast. There are examples of back-to-back schemes where both ac systems have low or
very low SCRs. On the other hand, it is difÞcult to visualize a practical case where power would be supplied
from a very low SCR ac/dc system over a transmission line. However, the application of a fast compensator
at the rectiÞer ac system would enable operation even in such a case. Of course, there is always the option of
strengthening the ac system (2.2.6).
Using only the inverter to provide fast voltage control in back-to-back schemes where both ac/dc systems
have very low SCR values may have some limitations. If both ac systems exhibit frequent and fast ac voltage
variations, inverter voltage control, coupled with automatic capacitor and inductor switching at the two ac
bus-bars, may not always provide acceptable performance. In such cases, consideration should be given to
improving the conditions of one of the two ac systems. This can be done by providing fast ac voltage control
by an independent compensator (2.2.7.1) or by strengthening one of the ac systems (2.2.6).
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3.4 Principal parameters
For ac/dc systems having low and very low SCRs, the ac voltage stability at the terminals of the convertor
station has to be fully analyzed and studied. Such a phenomenon can be responsible for the ac voltage excursions during steady-state as well as dynamic operation of the dc scheme. Fault recovery performance, temporary overvoltages, and overall ac/dc system transients and dynamic stabilities are also closely tied to the ac
voltage stability phenomenon.
The solution(s) adopted to alleviate such a problem stem from the following parameters, which directly
inßuence the severity of such a phenomenon:
a)
b)
c)
d)
e)
f)
AC system impedance (fundamental frequency)
Rated dc power
Rated reactive power (which depends on commutating reactance and on a and g)
Range of acceptable ac voltage regulation
Level of var compensation
DC control strategy
For a given system impedance and other system parameters shown in Figure 2-1, there will be a unique Pd/Id
characteristic for operation at g minimum (constant), which will represent the maximum power curve.
3.5 Trends and sensitivities of system parameters
3.5.1 AC system impedance
The closer that the system impedance approaches that corresponding to the CSCR, the greater the probability that the operation may take place at currents larger than the IMAP .
The curves of constant MAP have been drawn in Figure 3-7 [see B114] for different values of system admittances and for three different values of ac terminal voltage. For a system impedance having the angle f =
90°, ESCR has the numerical value of the susceptance B, and for a system impedance having the angle f =
0°, ESCR has the numerical value of the conductance G. It can be seen that the value of MAP, and therefore
of CSCR, does not vary much for system impedance angles in the practical range of, say, f = 70° to f = 85°,
which means that the simpler Equation (9) given in 2.5 can be normally used.
The variation of the terminal ac voltage was achieved by varying the emf behind the ac system impedance
without varying the value of impedance, in order to indicate the effect of ac voltage on MAP. In practice, a
disturbance, such as an ac line trip, would result in a change of both impedance and terminal voltage values.
3.5.2 Convertor reactive power consumption
It was shown in Clause 2 that QESCR gives a better indication of ac/dc system operation, because it takes
into account the convertor reactive power consumption (Qd). The values of CSCR and CESCR will be higher
for higher values of Qd . This means that the higher the Qd , the lower the value of MAP, and hence of power
transfer for the same values of SCR and ESCR. A value of QESCR equal to about 0.95 indicates that the
operation is near MAP (see 2.4).
4The
40
numbers in brackets correspond to those of the bibliography in Annex B of Part I.
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Conductance - G (G = ESCR at
= 0¡)
= 90¡)
0.2 0.4 0.6 0.8 1.0 1.2 1.4
U L = 1.0
-0.4
Susceptance - B (B = ESCR for
IEEE
Std 1204-1997
= 70¡
A
-0.8
B
U L = 0.95 pu
B
U L = 0.9 pu
A
-1.2
-1.6
A
-2.0
B
A. Unstable Region
B. Stable Region
X c = 0.2 pu, g = 18¡
Tapchanger fixed at
terminal voltage U L = 1.0
Constant Pd Control
Constant g
Figure 3-7ÑCurves for constant MAP for different ac systems admittance:
Figure
3.7
G (effective
conductance)
and
Curves for
Constant
MAP in
for
B (effective
susceptance)
perDifferent
unit of Pd AC
Systems Admittance
3.6 Possible improvements
3.6.1 Reducing the ac system impedance
The desired performance can always be achieved by increasing SCR; i.e., by reducing the ac system impedance. This can be done by Þnding a more suitable connecting point in the receiving ac system or by adding
an ac line. The former may not be possible to achieve and the latter may be uneconomical.
Another method employed in practice has been to use a synchronous compensator at the inverter station as
discussed in 2.2.6.
3.6.2 Control improvements for normal operation with Id < IMAP
In 2.2.4.2 and 3.2.2 it was pointed out that, due to ac system changes like line outages, the resultant MAP
value may be smaller than the required power, and stable operation can continue only in a constant-current
control mode at reduced power levels.
The following control action can be taken to minimize these disadvantages.
3.6.2.1 Sliding current limit
The use of a sliding current limit set at say 0.05 pu above the per unit power order prevents large uncontrolled
changes in power due to sudden ac voltage changes, as could be found in the case of a Þxed 1.1 pu current limit
used in many schemes. The use of a sliding current limit is of particular importance for operation at lower values of power. In Figure 3-8, it is assumed that the operation is at 0.5 pu of power at Id = 0.5 pu at an increased
ac system impedance, but having a value of SCR (i.e., OSCR), equivalent to the SCR = 3 of Figure 3-4. In this
case, a sudden increase of system impedance, due for example to a line trip, would result in a reduction of
MAP below the required 0.5 pu. A current limit of 1.1 pu or 1.05 pu could cause the collapse of the voltage
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and hence power transmission. However, a sliding current limit set at 0.05 pu of power order, in the example
of Figure 3-8, ILimit = 0.55 pu, would allow transmission to continue at only a slightly lower power level until
ac voltage is corrected by, for example, capacitor switching.
Power Pd (pu)
1.0
X c = 0.15 pu, g = 18¡
Q c = Q d = 0.54¥Pdn at U L = 1.0 pu
0.8
0.6
A
B
0.4
OSCR = 3.0
0.2
0
OSCR = 2.0
I LIMIT= 0.55 Idu
0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0
DC Current (pu)
Figure 3-8ÑOperation at reduced load sliding current limit
3.6.2.2 Temporary reduction of power order
The power order can be automatically reduced for ac voltage reductions below a preset limit, so that the
actual power is always some percentage smaller than MAP. In that way, the power will continue to be controlled in coordination with ordered current changes.
The time during which the power level is lower than required can be minimized by having available shunt
capacitor banks that can be automatically switched to restore the ac voltage. This will be effective, as the
voltage stability factor (VSF) is positive in current control.
There are a number of schemes where the operating point is sufÞciently near the MAP, so that a relatively
moderate, sudden ac voltage reduction may result in MAP-2 being lower than the power being transmitted.
The Itaipu scheme is designed to operate at CESCR of approximately 1.5; so far, the minimum OESCR in
service was 1.8 (the worst case studied was for ESCR = 1.55, Xc = 18%, g = 17°, and Qc = 0.6P). The power
control system has a slow voltage feedback. The time constant is chosen to match the speed of response of
the synchronous compensator voltage control systems (500 ms). For large voltage decreases, a changeover to
constant current control for a preset time takes place. A moderate voltage reduction in the inverter ac network may lead to a commutation failure that will activate the constant current mode. The recovery will, as in
most other schemes, take place in constant current control mode.
In the Nelson River scheme (minimum ESCR = 2.51, f = Ð75°, g = 18°, Xc = 20%, Qc = 0.6P) for reduced ac
voltage to 0.95 pu, operation is changed from purely constant power by replacing measured voltage, in the
master control circuit, by a Þxed dc voltage in order to prevent increasing current order with reduced voltage. It is released at 1.0 pu ac voltage. A damping capability, required by the ac system from the dc, is maintained, as is the important function of dc power reduction for tie-line trips.
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3.6.2.3 Operation with an increased g
If the normal operation is very near MAP, so that excursions beyond MAP may be unacceptably frequent, it
may be economical to design the inverter for normal operation at a g slightly larger than the minimum, in
order to provide some margin to deal with frequent ac voltage changes.
3.6.3 Normal operation with IDC > IMAPÑapplication of TCR or SR with constant g
If sufÞciently fast control of the inverter ac busbar voltage is provided by a SR or TCR, the power control
mode of operation required for system stabilization and frequency control would be stable, because ac voltage could be controlled faster than the voltage feedback that determines Iorder. Static compensators are
already used in service at the inverter terminals to control overvoltages (e.g., Cross Channel, Chateauguay).
Additional shunt capacitors would be required to compensate for SVC reactive consumption in normal operation and there would be a requirement for switching additional capacitor banks to keep the SVC in range.
The application of an SVC in this way should be considered for existing schemes where, due to ac system
changes, the operation at Id > IMAP may result and the existing dc equipment is not rated for operation at
larger g. For new schemes, it is likely to be more economical to design the equipment for operation at variable g.
A synchronous compensator could be used in the same way as described above for SVC, provided the control of ac busbar voltage is faster than the required power control speed; i.e., the voltage feedback that determines Iorder. However, it should be noted that in all schemes that are in service where a synchronous
compensator is used, the ac system was sufÞciently strengthened that the normal operating point is on the
left side of MAP (Id < IMAP).
3.7 Inßuence of dc controls
As indicated previously, the control mode employed is very important. The importance of the quality of the
controls cannot be overstated. Controls are discussed in Clause 4.
3.8 Methods of study
3.8.1 Hand calculation
For preliminary consideration CSCR, MAP, power reduction due to ac voltage reductions, etc., can be calculated by hand (or using simple digital programs) using steady-state equations. This can be done initially by
taking just the inverter into consideration. Similar calculations can be carried out by taking into consideration the combined operation of the rectiÞer and the inverter.
3.8.2 Digital system programs
Good load ßow and transient stability programs will provide correct results.
3.8.3 DC simulator
A dc simulator is normally used for more detailed studies required for design and stability criteria of control
circuits. Additional information is provided in Clause 7 and also in Part II, Clause 5.
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3.9 Discussion of power curves
3.9.1 AC/DC system having high SCRÑFigure 3-3
See Figure 3-3 for an ac/dc system having a high SCR.
Id
UL
Ud
Pd
Xc
g
SCR
Initial conditions point A on MPC-1
1.0
1.0
1.0
1.0
15%
18°
4.5
Possible immediate overload at MAP-1
1.74
0.83
0.73
1.28
15%
18°
4.5
Conditions following a line trip before current
increaseÑnew initial conditions, point B on
MPC-2
1.0
0.984
0.983
0.983
15%
18°
3.0
Restored conditions
1.04
0.98
0.929
1.0
15%
18°
3.0
Possible immediate overload at MAP-2
1.3
0.85
0.814
1.06
15%
18°
3.0
Higher power values (Pd) than those indicated above could be obtained only if the ac voltage applied to the
inverter is increased.
3.9.2 AC/DC system having low SCRÑFigure 3-4
The conditions in Figure 3-4 are as follows:
Initial conditions, point A at MPC-1
Id
1.0
UL
1.0
Ud
1.0
Pd
1.0
g
18°
Xc
15%
SCR
3
g
18°
Xc
15%
SCR
3
Possible immediate overload to MAP-1
Id
1.32
UL
0.87
Ud
0.83
Pd
1.08
Conditions following a line trip before current increaseÑnew initial conditions, point B on MPC-2
Id
1.0
UL
0.93
Ud
0.92
Pd
0.92
g
18°
Xc
15%
SCR
2
However, the current would immediately increase up to the current limit, point C on MPC-2
Id
1.1
UL
0.84
Ud
0.81
Pd
0.9
g
18°
Xc
15%
SCR
2
Ud
0.96
Pd
0.93
g
18°
Xc
15%
SCR
2
Conditions at MAP-2
Id
0.96
44
UL
0.96
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Higher power values can be obtained only if the ac voltage applied to the inverter is increased.
3.9.3 AC/DC system having very low SCRÑFigure 3-5
See Figure 3-5 for the ac/dc system having a very low SCR.
Initial conditions, point A at MPC-1
Id
1.0
UL
1.0
Ud
1.0
Pd
1.0
g
25°
Xc
15%
SCR
1.5
Xc
15%
SCR
1.5
Possible immediate overload, point B on MAP-2
Id
1.07
UL
0.96
Ud
1.0
Pd
1.07
g
18°
Conditions following a line trip before reduction of g, point C on MPC-3
Id
1.0
UL
0.81
Ud
0.8
Pd
0.8
g
25°
Xc
15%
SCR
1.3
However, g would immediately reduce to its minimum, point A on MPC-4
Id
1.0
UL
0.95
Ud
1.0
Pd
1.0
g
18°
Xc
15%
SCR
1.3
Higher values can be obtained only if the ac voltage applied to the inverter is increased.
3.9.4 Discussion of results
It should be noted that the above results are obtained for the speciÞed inverter and ac system data and apply
just to this example. Also, it should be remembered that only the inverter characteristics were considered;
i.e., any restrictions that a practical rectiÞer may impose on power transmitted were ignored. However, the
examples do serve to indicate the possible performance with ac/dc systems of different SCR values.
High and low SCR systems will allow an immediate overload up to the value of MAP; i.e., even without ac
voltage control, provided that there are no other limitations, such as inadequate output from the rectiÞer or
by equipment rating. The higher the SCR of the system, the higher the value of the immediate overload. The
low SCR system cannot maintain the power at the level being transmitted, following the assumed ac system
disturbance; a current limit would allow the transmission to continue at a reduced power level.
The amount of immediate overload when operating with very low SCR systems depends on the design rating
corresponding to the nominal value of g. In the particular example of Figure 3-5, the normal operation at
g = 25° allows an immediate overload of 1.07 pu and just permits a system disturbance that increases the ac
system impedance by 15% without loss of power.
Satisfactory operation with very low SCR systems depends on good ac voltage control to maintain g near its
nominal value and to keep ac voltage within prescribed limits despite steep voltage changes, due to dc current variation.
It should be also noted that the large sudden system changes assumed in these examples may cause, in practice, a commutation failure, which is discussed in Clause 10.
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4. Control and protection for dc transmission
4.1 Introduction
Controls are involved to a greater or lesser extent in most phenomena of interactions between ac and dc
systems. The control system is of immediate importance for stability and performance during disturbances.
Special control functions can be added to improve, in many cases, the behavior of the total transmission
system.
If the convertor stations are connected to a high SCR system (i.e., has low impedance), the control system
design is straightforward and a high speed of response can be achieved in most cases. The exception to this
would be the schemes having long dc cables or very long transmission lines. With low and very low SCR ac
systems, on the other hand, stabilization of the dc controls requires more care and it may be necessary to
accept that recoveries from ac system faults are slower than if the ac network were strong.
4.2 Hierarchical division of the dc control system
4.2.1 Introduction
Several control levels can be found in a dc scheme since an ac/dc system itself can be considered as divided
into different hierarchical levels. Power dispatch, system frequency, ac voltage, machine signals, etc., constitute the constraints of the ac ÒworldÓ that should be correctly treated in a coordinated manner by the relevant
control levels, in order to provide a stable ac/dc interconnection.
The magnitude of time constants is different for each control level. The shortest time constant is related to
valve electronics. Time constants increase in value (and frequencies of concern become lower) as the controls move closer to the ac system. Figure 4-1 indicates the various levels and typical time constants associated with each control level.
Modulation Signals and
Constant Frequency
Type of
Control
Control
Constant Power Loop
VDCOL
Constant Current Loop
Firing Control
Limits
C
Harmonic
Instability
Type of
Interaction
Recovery &
Overvoltages
Valve & Firing
Level of
Control
STABILITY
(= 1ms)
Pole
(10 to 500ms)
Master
(Up to 10s)
Figure 4-1ÑHierarchical levels of HVDC controls with typical time constant
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4.2.2 Thyristor and valve control level
The lowest hierarchical level in the control system is the valve and thyristor control equipment. This covers
the electronic equipment used for transmission of control pulses to the valve for the Þring of the individual thyristors, and for supervision and monitoring of valve status. A simpliÞed block diagram is given in Figure 42. The thyristor control units (TCUs) communicate with the valve control system and convert received Þring
pulses, normally light pulses transmitted by Þber-optic light guides, into current pulses applied to the thyristor
gates. Return channels from the TCUs to the valve control system are often used for thyristor supervision.
TCU
From
Converter
Control
Valve
Control
TCU
TCU
TCU
Figure 4-2ÑThe thyristor and valve control levels in the control hierarchy
4.2.3 Convertor and basic control level
The convertor control level consists of the convertor Þring control. This subsystem determines the Þring
instants for all valves of the convertor. The Þring control system can operate in one of several modes. The
principal modes are as follows:
a)
b)
c)
Minimum alpha control and minimum commutation margin control, which deÞne limits of convertor
control and must always be able to override other modes of control
Direct current control
Direct voltage control
Direct current and direct voltage modes of control are used to execute the requirements of higher level control loops that control system quantities such as transmission power and reactive power consumption.
In current control, which is the normal rectiÞer mode of operation, the delay angle alpha is determined by a
control signal from a current controller that is used to control the current in the dc circuit.
4.2.4 Pole control level
The current control ampliÞer (CCA) is found in the pole control level, which is next in the hierarchy. When
two or more convertor groups are connected in series in the same pole they must carry the same direct current,
and therefore must be served by a common control ampliÞer. Most dc systems operate under the current margin method, which will be discussed later. One of the principles involved in this method is that both rectiÞer
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and inverter are provided with a current controller, but the controller in only one of the stations is active. The
controller in the inverter station is normally made ÒinactiveÓ by making its current order smaller than the order
in the rectiÞer station. However, the status of the two controllers can be dynamically changed during and after
disturbances. The convertor and the basic pole control levels are illustrated in Figure 4-3, in which CFC1 and
CFC2 indicate convertor Þring control systems for two 12-pulse convertors in the pole. CCA is the current
control ampliÞer and COL is the current order limiter (see 4.6).
Io
COL
+
CCA
CFC1
CFC2
CFC = Converter Firing Control
CCA = Current Control Amplifier
COL = Current Order Limiter
Figure 4-3ÑConvertor and basic control levels in the control hierarchy
The control functions considered so far represent the basic control system needed to operate a dc system.
This part of the control system is normally not designed for a speciÞc project, but parameter values and some
special functions are changed to suit a particular system.
4.2.5 Pole master control level
The next level in the hierarchy is the pole master control level shown in Figure 4-4. Master control functions
can also be found on the bipole level, but it is often considered sound design philosophy to refer as many of
the master control functions to the pole level as possible, which is advantageous from the availability point
of view. The pole master control (PMC) equipment normally includes such functions as power control
(which determines the current order), current order transmission between stations, and current order limitation for overload control. Also, power order ramping and power modulation for ac network stabilization may
be performed by the pole master controller.
4.2.6 Bipole control level
Control functions on the bipole level should be avoided as far as possible. However, some functions related
to total transmission power must be situated in the bipole level control. The integrating frequency controller
intended for constant frequency control of a receiving island network is usually common to the two poles of
a bipolar transmission scheme. Also, a reactive power controller, which switches shunt banks and Þlters and
which generates orders to change control angles, is preferably a bipolar control function.
In addition to control functions, as discussed above, protective and sequence control functions are also found
on each of the hierarchical levels with segregation to lowest possible level. For example, protection on the
bipole level (e.g., protection that can trip the whole bipole) should be avoided for availability reasons.
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COL
Bipole
Power
Order
PMC
IEEE
Std 1204-1997
+
CFC
MW
PMC
+
-
CFC
PMC = Pole Master Control
Figure 4-4ÑPole master control in a bipolar transmission
4.3 Types of interaction between controls and the ac system
4.3.1 Introduction
The control systems for a dc transmission must be stable with adequate stability margins in the whole range
of operation.
It is easier to achieve control system stability and fast response when the ac network has a large SCR value
than when it has a low or very low SCR. For instance, it may be impossible to achieve a fast power control
system if the receiving ac network has a very low SCR. This problem can sometimes be solved by slowing
down the direct voltage signal fed back to the power controller to allow the ac system voltage control to act
before the current order is signiÞcantly changed. This can reduce the inßuence of the ac voltage variations.
With line-commutated convertors, which are used for dc systems, the commutation process depends on the
ac voltage waveform, and therefore the commutating voltage is the main interface parameter between ac and
dc systems.
4.3.2 Firing of thyristors
4.3.2.1 Thyristor Þring voltage and the availability of gating pulses
Two conditions are required simultaneously for the thyristor to start conducting: A positive voltage applied
across the thyristor must be larger than a given minimum and a positive current must be injected to the thyristor gate. SufÞcient voltage is made available by limiting the minimum alpha to a value of, say, 2° to 5°.
The Þring signal transmitted from ground potential is used to release the current pulse, which is generated at
the individual thyristor level.
The energy for the Þring pulse derives from capacitors at the thyristor levels, charged by the ac voltage
applied across the valve. It is important to be able to adequately charge these capacitors, even if ac voltage
has a low value for a prolonged period of time. It is particularly important for systems where dc represents a
large proportion of power infeed to be able to recover quickly from an ac or dc system fault, in order to prevent the collapse of the ac system. It is also important to transmit as much power as possible during system
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faults when ac voltage may be low. This can be done only if the ability to provide energy for the Þring pulses
is not lost during the disturbance. In practice, other factors may impose a minimum ac voltage for convertor
operation.
4.3.2.2 Thyristor reÞring
A valve should be able to reÞre during the conduction interval deÞned by the Þring control system, after a
current extinction due to, for example, a brief ac voltage reduction to zero as a consequence of an ac system
fault. This requirement is not as obvious as it may seem, because modern valve control systems are based on
the principle of Þring the valve by transmitting one or a small number of short pulses to the valve at the
beginning of the conduction interval. Thus, the requirement of reÞring at current extinction means that the
valve control system must be designed to generate and transmit new Þring pulses when the voltage builds up
across the valve during the conduction interval, e.g., during the period that a valve would normally conduct.
This matter can also be handled by the thyristor control unit if start and stop pulses are received from the
valve control system.
If the valves are able to reÞre at current extinction, the dc system can operate with very low currents (below
the limit for continuous current operation), and can be used to form a very low load to a generator station in
radial operation with the dc link during the startup of the generators. This property of the dc system is also
important when the transmission system is used for the infeed of power to an island network if the dc transmission is used for acceleration of the synchronous compensator from a low frequency to rated frequency as
is the case in the Gotland transmission (see Clause 9).
4.3.3 Interactions with the Þring controls
4.3.3.1 Individual-phase Þring control
The individual-phase control system applies a method of Þring pulse generation directly synchronized to the
ac voltage waveform. It also creates an unintentional feedback loop from this waveform via delay angle
determination, phase current variation, ac voltage ßuctuation, and thence back to the voltage waveform.
This is illustrated in Figure 4-5, in which the quantities involved in the feedback loop are denoted as superimposed disturbances; i.e., delta alpha (for variations in delay angle), delta Iph (phase current), delta UAC
(phase voltage), and delta Ucf (control function). Here Ucf is a control function derived from the ac bus voltage and is used for direct determination of the phase position for Þring; i.e., the delay angle. It should be
noted that even if the direct current, Id in the Þgure, is ideally smoothed, a disturbance in alpha will cause
disturbances in phase currents. The most important parameters for the loop gain are the equivalent network
impedance Zn and the value of the direct current. A higher Zn (i.e., a weaker ac network) and a higher direct
current result in a higher loop gain and a higher risk for instability.
4.3.3.2 Equidistant, or phase-locked oscillator, Þring control systems
The harmonic instability phenomenon was one of the main reasons for developing the equidistant Þring control system or, using another name, the phase-locked oscillator control system, used in all modern dc
schemes. It should be noted that an equidistant Þring control system does not give equal distances between
Þrings in all situations, not even in steady-state operation. Exact equidistant Þring is obtained only in steadystate operation with completely balanced commutation voltages. The name Òequidistant Þring controlÓ refers
to the fact that each Þring is Þxed in time with reference to the previous Þring and not to the previous zero
crossing of the commutation voltage, which is the case in the individual-phase control system. The equidistant type of Þring control system does not rely on a control function derived from the ac voltage but is only
indirectly synchronized to the ac voltage by the current feedback, and accordingly the unintentional feedback loop discussed in 4.3.3.1 is broken.
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
U
a.c.
Z
I ph
N
I ph
Id
U
6
Iorder +
-
CFC
6
IRESP
Figure 4-5ÑCurrent control with individual-phase Þring control system
Figure 4 5
As shown in Figure 4-6, the basic element in an equidistant Þring control system operating in current control
mode is a voltage-controlled oscillator (VCO), the output pulse signal of which in steady state (Iorder = Iresp)
has a frequency equal to the pulse number for the convertor multiplied by the ac system frequency. The control pulse generator separates the pulse signal into one signal per valve. As soon as a deviation occurs
between current order and current response, the frequency of the VCO will change temporarily. Steady-state
operation will be restored, with a new or the predisturbance value at the delay angle a, following a transient
delay. Using this type of Þring control allows stable operation with a weak rectiÞer ac network.
4.3.3.3 Commutation margin angle control for inverters
The inverter must always be provided with a Þring control function which, as far as possible, guarantees that
Þring does not take place later than at the instant which would result in a minimum commutation margin.
Two techniques have often been utilized for the inverter Þring control: g predictive and g feedback. In the g
predictive approach, the Þring pulses are ordered according to a calculation of predicted voltage-time area
for commutation and extinction. The other approach executes the Þring pulses according to the difference
between a g order and a measured value of g. Predictive inverter Þring is, by nature, individual per valve or
phase, but can be provided with a balancing circuit to attain equidistant Þring and stable operation when
feeding a weak ac network.
4.4 Current control
The design of the direct current control system is determined by main circuit parameters; e.g., the inductance
of the dc reactor, the characteristics of the dc line, and the impedances of the ac networks and of the convertor transformer. The impedance of the receiving ac system is the most important parameter. Thus, the characteristic of the inverter considered as a load to the rectiÞer is dependent on characteristics of the inverter ac
network.
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U
a.c.
Z
I ph
N
I ph
Id
6
I order +
-
VCO
6
CPG
IRESP
VCO = Voltage Controlled Oscillator
CPG = Control Pulse Generator
Figure 4-6ÑCurrent control with equidistant Þring control system
Typical natural frequencies of the current controller for cable and long overhead line schemes are in the
range of 5Ð30 Hz. Whether these frequencies would interact with the network (thermal machines, for
instance) or not should be investigated for each application.
The normal way of illustrating the cooperation between a rectiÞer and an inverter is by reference to the wellknown Ud/Id diagram. In the traditional way of controlling dc transmission, the rectiÞer controls the current
and the inverter operates with constant margin of commutation, giving the point of operation indicated by A
in Figure 4-7. As the inverter is given a current order lower than the rectiÞer by the value of current margin,
it is forced into minimum commutation margin control. The strategy is called the constant current margin
control, which gives the maximum dc voltage for a given ac voltage applied to the inverter.
U
d
Rectifier
A Inverter
I
d
Figure 4-7ÑUd/Id characteristics for an HVDC transmission system,
simple version (Udio constant)
Figure 4.7
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The slope of the nearly horizontal line of the inverter characteristic is such that an increase in current results
in a decrease in voltage; i.e., the rectiÞer current control system experiences the inverter as a negative resistance load for small and low frequency current variations. This is easily handled by correct tuning of the current controller, as long as the magnitude of the negative resistance is moderate.
The slope of the nearby horizontal part of the invertor characteristic can be obtained from Equation (14) for
the inverter direct voltage for constant g operation neglecting resistive voltage drops (see Annex A of Part I).
Id
U d = U dio cos g Ð d x -------- U dioN
I dN
(14)
Normally, characteristics such as those shown in Figure 4-7 are drawn for steady state conditions, assuming
constant applied ac voltage. According to Equation (1), for these conditions, the slope of the inverter characteristic is only determined by the convertor transformer impedance; i.e., dx . However, Udio follows the ac bus
voltage at dynamic variations; therefore, increased current means decreased Udio, which is restored to its
nominal value, at a longer timescale, by the convertor tap-changer and by the ac voltage control by, for
example, capacitor switching.
Thus, in practice, for dynamic current variations, the negative resistance of the inverter as seen from the rectiÞer is also highly dependent on the network impedance. It is normally possible to attain stable operation by
adjusting the control parameters in both rectiÞer and inverter basic control systems. If the dynamic slope of
the inverter characteristic is large, as shown in Figure 4-8, instability may result.
U
d
Rectifier
B
A
Inverter
C
I
d
Figure 4-8ÑUd /Id characteristics for weak inverter ac system (Udio not kept constant)
The modiÞcation shown in Figure 4-9 is obtained by increasing the margin of commutation by increasing g
in proportion to the decrease in current below a set reference value. The result of this measure is that the negative slope is replaced by a positive slope in the region of decreasing current. With a current oscillation
superimposed on the average current value, the average resistance will then be less negative or even positive.
This simpliÞes the conditions for the rectiÞer current control system considerably. It should be noted that the
operating point A should move only vertically and not in a horizontal direction for inverter ac network voltage variations. The characteristic of Figure 4-9 is also useful for avoiding the so-called three-point crossover
instability indicated in Figure 4-8.
The operating point A of Figure 4-9 corresponds to operation at minimum commutation margin as normally
implemented to minimize the cost of the convertor station.
An alternative solution is presented in Figure 4-10a, in which the characteristics are so arranged that the normal point of operation is moved down along the part of the characteristic with positive slope. Now the
inverter is able to increase the voltage at increased direct current and accordingly counteract a further
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U
d
Rectifier
A
Inverter
I
d
Figure 4-9ÑModiÞed inverter Ud/Id characteristic
Figure 4.9
increase. This method has been found to be very effective when the inverter is connected to a weak ac network. The normal operating point A corresponds to a value of g larger than the minimum.
Another modiÞcation, shown in Figure 4-10b, is similar to Figure 4-10a, but with a horizontal characteristic
near A; i.e., with constant dc voltage control. This characteristic is often used to achieve stability in the
Òconstant powerÓ control mode when operating with weak ac systems. Also in this case, the normal value of
g is larger than the minimum (see also 3.6.2.3).
U
d
Rectifier
A
Inverter
I
d
Figure 4-10aÑModiÞed inverter characteristic with normal operation with g higher than
minimum
Figure 4.10a
Constant power factor control has been used in some cases for securing stable operation of an inverter. Basically, this control system employs constant dc voltage control with a minimum g limit as shown in
Figure 4-10c, combined with the convertor transformer tap control to keep the voltage of the transformer
valve winding constant. The margin angle is kept minimum in full-load operation and is effectively
increased in partial-load operation.
Current control stability with a weak inverter ac network can also be improved by designing the system for
current control in the inverter as shown in Figures 4-11. This alternative suffers, however, from increased
station cost in the same way as the solution presented in Figure 4-10a and 4-10b. Normal operation with g
higher than the minimum value for a given dc line voltage, implies that the valves must be designed for
higher damping circuit losses and higher ac voltage, and the resultant higher reactive power consumption of
the inverter must be compensated. However, it may be justiÞed to operate with a high steady-state g as an
alternative to the use of fast static var compensators for ac voltage stabilization.
54
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Figure 4-10bÑAlternative inverter characteristic with normal operation with g higher than
minimum
Figure 4-10cÑInverter characteristic for constant power factor control with
normal operation with g higher than minimum
U
d
Rectifier
A
Inverter
I
d
Figure 4-11ÑUd/Id characteristics for current control performed by the inverter
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4.5 Power control
From a steady-state point of view, power control of the rectiÞer with constant g control of the inverter is not
in itself stable if the strength of the inverter ac network is below a certain value (operation to the right of the
MAP point in Figure 4-12, with g constant). If the power order is increased, the increase in direct current will
cause a decrease of the voltage by such a magnitude that the net effect would be a decrease in power infeed
to the ac network. The voltage decrease will generate a still higher current and the power will further reduce
until the current limit is reached. For operation with a low SCR ac system, three methods were used in practice to improve the operating conditions as discussed in 3.6.2.
Ud
MAP
MAP
B
MPC
A
Id
I MAP
Figure 4-12ÑCharacteristics of HVDC transmission in power control with inverter
operating at an increased g
However, for operation with low or very low SCR ac systems, when the operating point may normally correspond to dc currents higher than IMAP , one possibility is to establish a sufÞciently fast control of the ac voltage to avoid normal operation with a value of dP/dI being negative. For example, this can be done by very
fast static var compensators as discussed in 3.6.3 or by varying the value of g to control voltage; i.e., by
arranging for the inverter to behave as a static compensator. In this case the normal operating point will be at
point A of Figure 4-12. The range of this type of behavior is determined by the allowed range of variation of
g (distance between points A and B), and sooner or later minimum g will be reached at point B. When minimum g is reached, the inverter will operate in constant g control, and operation will try to jump to the current
limit as before. The effect of this can sometimes be much improved by sliding limits; i.e., current limits tied
to a power order that limits current to just above the normal value for the power order (see also 3.6.2.1).
4.6 Reduction of the direct current at low voltage
To avoid feeding a high current into a disturbed ac network, and to get a controlled recovery from the disturbance, it is normal to reduce the current order when the direct voltage is reduced. The break points D and E
in Figure 4-13 are typically between 70% and 30% of dc voltage, and in special cases, even higher, depending on ac system requirements. The higher voltage is applied when the receiving ac network is sensitive to
disturbances that could cause large voltage ßuctuations as in the Itaipu scheme.
The main difference in the alternative arrangement of Figure 4-14 is that the part E-F of the rectiÞer characteristic is kept horizontal.
The terms VDCOL (voltage-dependent current order limit) and LVCL (low-voltage current limit) have been
used for the function that reduces the current when the voltage decreases.
56
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
Ud
Rectifier
A
D
Inverter
E
F
Id
Figure 4-13ÑUd /Id characteristics with current order reduction at low voltage,
alternative 1
Ud
Rectifier
A
Inverter
D
E
F
I order
Id
Figure 4-14ÑUd /Id characteristics with current order reduction at low voltage,
alternative 2
4.7 AC system instabilities
The following instabilities are examples of where the convertors can help the ac system:
a)
b)
c)
Low-frequency instability, at frequencies from about 0.1Ð2 Hz. This is the region of inter-machine
and inter-area electromechanical oscillations. The dc link can contribute to the damping at these frequencies by the addition of special control loops from a measured ac quantity, such as frequency or
phase angle of the ac system. The feedback signal is generally Òac-coupled,Ó so that steady-state
operation is not affected.
Very-low-frequency instability, below about 0.1 Hz. This is the system frequency control region, relevant to machine speed control by turbine governors. Comments are as for item a). In addition, control of absolute frequency is sometimes used, either with an integral (ßat) power/frequency
characteristic or with a power/frequency droop, as for generators.
The ability of a dc link to change power relatively quickly (power run-back) can be useful as an
override feature. For example, if a substantial reduction of ac voltage occurs (perhaps for a reason
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
not connected with the presence of a dc link), the dc link can be ordered to reduce power quickly,
and hence the reactive power consumption, so as to restore ac voltage sufÞciently to prevent ac system collapse. Another example of run-back application is the case in which an ac line connecting the
convertor station to the ac network is lost.
As mentioned above, dc schemes can be used to counteract inter-machine or inter-area power oscillations by
the utilization of external-area signals, such as frequency or voltage deviations, phase angle changes, or
power changes in an ac parallel line.
Originally, the dc controls were designed to improve damping to real power oscillations by modulating the
dc power Pd . No concern was taken to the reactive power changes delta Qd resulting from the modulation
Pd . However, as the ac network becomes weaker, variations in reactive power will cause voltage variations,
which can be detrimental to overall system stability. More recently, several techniques of modulation have
been proposed with good results:
Ñ
Ñ
Ñ
Modulation of g as a function of ac voltage variations
Direct voltage control by inverter g
A coordinated modulation of transmitted active power and reactive power consumed by one of the
convertor stations
4.8 Inßuence on the control of resonances in the ac network
Clause 5 discusses harmonic and resonance inßuences on control design.
4.9 Summary of convertor control instability phenomena
In principle, a combination of one or more dc links, including their Þlters, dc lines, and the ac systems with
their machines, lines, and loads, is mathematically a single entity. It is usually convenient to subdivide instabilities into several types, distinguished by their frequency referred to the dc side, as follows:
a)
Super-synchronous instability, at frequencies above fundamental. This is sometimes loosely called
Òharmonic instability,Ó though in general it is at a non-integer frequency.
As mentioned earlier, harmonic instability was a problem in some earlier dc systems, but modern
control principles should eliminate this problem.
b)
Core-saturation instability, at fundamental frequency referred to the dc side (second harmonic plus
dc referred to the ac side) with convertor transformer cores saturated.
This can occur with a low or very low SCR ac system with certain resonance conditions, as discussed in Clause 5. It is cured by the proper choice of control constants or by the addition of special
control loops.
58
c)
Subsynchronous instability, at frequencies from about 5Hz to 40 Hz. This can occur either at a frequency unrelated to any natural frequency of the ac system, or in conjunction with machine torsional
mechanical resonances. This is cured by the use of suitable control types and control constants,
sometimes with extra control loops (see Clause 6).
d)
Power control instability. With ac systems represented by Þxed Thevenin equivalents, this is a ÒrunawayÓ condition (in practice prevented by current limit), mathematically at zero frequency, which
occurs in restricted conditions with an ac system having a very low SCR. This is discussed in
Clause 3 and 4.5.
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It should be stressed that the controls must be stable for operation in current control mode with the inverter
operating at constant g. In all control modes (constant power at constant g, variable g, or constant g with
static var compensators), during a temporary low ac voltage, operation will take place in current mode with
the inverter at constant g.
4.10 System parameters of principal interest to the controls
The response time of the dc controls is short compared to other time constants of the network. The speed that
can be applied to the dc controls will be dependent on the capacity of the network to support variations of the
real and reactive power of the convertors. For instance, it should be noted that a very rapid recovery after an
ac system disturbance may lead to a commutation failure if the inverter ac network has a high impedance.
In designing the controls for a given power scheme, one should consider the following aspects:
a)
b)
c)
The network impedance as a function of frequency should be known (preferably to above the third
harmonic), in magnitude and phase. This parameter is important for identifying possibilities of parallel resonance in the ac network or ac/dc/ac coupling via dc line harmonic magniÞcation; these
should be damped by the controls.
The speed of the dc link recovery after faults should be such that it satisÞes the conditions of both
networks, at the rectiÞer and at the inverter side, if they are isolated. If there are other interconnections or a parallel ac line, the problem of adjusting the controls is quite different, because the performance of one station can greatly inßuence the other station. Studies should be carried out to identify
the receiving and sending end ac network needs, in terms of stability, overvoltage levels, etc., and the
controls should be designed accordingly.
The presence of other fast voltage control devices, such as static compensators in the vicinity of the
convertor station, may inßuence the dc controls design.
4.11 AC voltage variations
4.11.1 Load rejection overvoltages
If the ac networks have high system impedance (low and very low SCR ac systems), high ac overvoltages
will occur at the loss of transmitted power. The reason is that the reactive power consumption is reduced or
eliminated when transmitted active power is lost while the compensation equipment, Þlters, and shunt banks
are still connected (see Clause 8).
Loss of full load is of course the worst case and can be the consequence of a permanent fault in the dc system
or a loss of commutation voltage in one of the ac networks.
A dc scheme should be so designed as to make the tripping of a bipole an extremely rare event. In the case of
monopolar transmission, the loss of the whole transmission is, of course, more probable.
The overvoltage problem can be minimized by combining the convertor blocking controls with an interstation control sequence that trips Þlters and shunt banks as required.
Some form of backup to the interstation sequence control system must be available for the case in which the
telecommunication system is out of order. Such a backup can be obtained by including protection that trips
Þlters and shunt banks at high ac overvoltage. The action from this protection must be delayed and coordinated with ac network line protection in order not to trip the reactive elements at load rejections caused by
temporary ground faults in one of the ac networks.
For a fault in the inverter ac network, the rectiÞer continues to feed current into the dc circuit with large
delay angle alpha. This means that the convertor consumes a sufÞcient amount of reactive power to limit ac
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
voltage rise. If the same type of fault occurs in the rectiÞer ac network, it would be theoretically possible to
let the inverter feed current into the dc line at a large control angle. However, an inverter must be prevented
from feeding a current through a ground fault on the dc line, and for this reason it is normally provided with
an alpha minimum limitation at, say, 100°. It is possible to discriminate between ac and dc faults by transmitting an indication from the rectiÞer to the inverter informing the latter that the fault is in the ac network
(i.e., not on the dc line). However, point-to-point dc schemes should also operate without the telecommunication system. Overvoltages in the absence of telecommunications must be taken into account when considering the insulation coordination.
4.11.2 Temporary overvoltage at recovery after an ac system fault
When the ac voltage recovers following an earth fault, the convertor transformers are energized and harmonic inrush current is generated. Recovery after a close three-phase fault is the most critical case. If the ac
side impedanceÑthe parallel combination of the ac network and the Þlter and shunt banksÑis high for the
inrush current harmonics, the temporary overvoltage on the ac bus may be high until the current starts to
ßow in the dc circuit.
To minimize these overvoltages, it is important to ensure that dc current starts to ßow at low dc voltage as ac
voltage recovers. Some control systems are designed to allow dc current to ßow at a reduced value during
the fault so as to avoid the delay on ac voltage recovery.
4.11.3 Reduction of ac network voltage variations by dc controls
4.11.3.1 Voltage change on reactive switching
When a shunt reactive bank is switched at a dc terminal, the system voltage changes in the vicinity of the terminal. At buses that directly serve consumers, the voltage change could cause the consumersÕ lights to blink.
If the voltage change were to occur frequently, the result might be annoying ßickering of lights.
Generally, weak systems exhibit a high sensitivity of voltage change on reactive switchings. Consequently,
the required limit on voltage change for reactive switching would often establish the size of reactive banks;
i.e., Þlters, capacitors, and reactors. Parameters, besides the bank size, that inßuence the voltage change on
reactive switching are as follows:
Ñ
Ñ
Ñ
Ñ
The ac system impedance
The amount of shunt compensation already connected to the bus
The amount of power being transferred by the dc convertor
The natural action of the dc convertor and its controls following the switching event
These key parameters must be considered in establishing an appropriate voltage change criterion for a convertor terminal and in determining the appropriate size of capacitor, Þlter, and reactor banks for the purpose
of limiting ßicker.
The appropriate criterion for limiting the voltage change caused by reactive switching must also be based on
the following considerations:
Ñ
Ñ
Ñ
60
The degree of consumer dissatisfaction caused by ßicker resulting from the voltage change
The relative frequency of switching events that cause the voltage change
The relationship of voltage change at the convertor commutation bus to the voltage change at lower
voltage buses serving consumers (the higher the impedance between the convertor commutation bus
and low voltage buses to which consumers are connected, the lower the voltage change on the lower
voltage system)
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The permissible ßicker limits in the Electrical Transmission and Distribution Reference Book [B26], Ellert
et al. 1978 [B27], and in The Visual Perception and Tolerance of Flicker [B83] provide some guidance in
this area. Considering a typical frequency of reactive switchings in dc installations (about 2/h to 2/min), it
appears that 2Ð3% is a reasonable upper limit on voltage change to avoid customer dissatisfaction due to
voltage ßicker.
Moreover, a suitable criterion for voltage change on reactive switching should permit a slightly higher limit
on voltage change at low power transfer levels than it would at rated power transfer levels, because dc systems will seldom operate near minimum power transfer levels and because shunt banks are not frequently
switched in such situations.
4.11.3.2 Application of dc controls
The consumption of reactive power in a dc convertor is, among other parameters, dependent on the control
angles a or g. A control function can be used to limit variations of ac voltage by varying the control angle of
the convertor. This type of control is suitably applied in the convertor station that determines the direct voltage.
However, it should be noted that varying the angle, and by this, the consumption of reactive power in one convertor station, also results in a corresponding variation in control angle and reactive consumption in the other
station. It must be determined that this is acceptable before a decision is made to use this type of control.
To limit ac voltage variations in both directions, the inverter must operate in steady state with a g higher than
the minimum value. This means higher equipment costs for valves, convertors, transformers, and reactive
compensation equipment, and also higher losses, but this may still be the cheapest solution.
In cases where it is sufÞcient to limit only the overvoltages, normal operation can be at g minimum, avoiding
the extra cost of the equipment.
To reduce the variations in ac voltage caused by shunt bank switching, a step change of suitable magnitude
in g can be coordinated with the bank switching. When switching in a capacitor bank, g is increased as simultaneously as possible. To switch off a bank, g is Þrst slowly increased; and when the bank is switched off, g is
simultaneously decreased in a step back to the normal value.
4.11.4 Tap-changer control
The convertor transformers are normally provided with tap-changers that are integrated into the control system to inßuence given dc quantities.
With an inverter in constant commutation margin control the tap-changer is often used to keep the direct
voltage in steady-state close to a rated value. In a current-controlling rectiÞer, it is normally used to control
alpha to a value around a rated value. Other variations are sometimes used, such as to control g in an inverter
operating in closed loop Id or Ud control.
In all cases, the objective is to increase or decrease the voltage on the valve side of the convertor transformer
by increasing or decreasing the turns ratio. However, this change in transformer turns ratio also changes the
reactive consumption of the convertor, and this may counteract the tap-changer stepping. Thus, a decrease in
the turns ratio, with the intent of increasing the valve side voltage, may increase the reactive consumption of
the convertor to such a degree that with a low or very low SCR ac network, the effective change in the valveside voltage will be very low. In such a situation, many tap-changer steps must be taken to attain the necessary variation in valve-side voltage, with the consequence that the effective tap-changer range will be low,
and the tap-changer will operate very frequently.
With a low or very low SCR ac network (SCR below about 2.0 and depending on the impedance angle) the
net effect in voltage variation when stepping the tap-changer may be even negative; i.e., the valve-side voltage will decrease when the transformer network-side turns ratio is decreased, and vice versa. This phenomenon is discussed in Piwko et al. 1986 [B67].
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4.12 AC network frequency and stabilization control
4.12.1 Introduction
The inherent controllability of the power transmitted by a dc system is unique in electrical power transmission; i.e., the power transmitted by the dc line is easily controlled with a high speed of response. Furthermore, the interconnection of two or more ac systems or of two or more buses in one ac system by a dc link is
asynchronous, and the transmission stability is not affected by a phase angle difference.
Thus, the dc transmission can be used for stabilization of an ac system by modulating the power transmitted
in accordance with the variations in some ac system quantity, such as frequency or phase change. The link
can also be used to directly control the frequency of an ac network connected to one of the substations.
These applications will be discussed below with reference to some typical cases.
4.12.2 Constant frequency control
A dc system can be used for transmitting power to an isolated area network without local generation, and
with a synchronous compensator as the dominating rotating inertia. The frequency of this network must be
controlled by varying the power transmitted on the dc line to attain balance between the load in the network
and the infeed of power. To do this, the deviation from nominal frequency in the island network is measured
by a frequency discriminator and fed to a control ampliÞer. The output from the latter is used as a current
order or forms a contribution for an operator-set current or power order on the master control hierarchical
level.
By incorporating such a control system, the frequency can be kept very close to the nominal value as long as
the dc transmission is in operation. The largest frequency deviation is, however, obtained during serious
faults in the ac network to which the rectiÞer is connected, and this deviation is in the worst case determined
only by the load, the inertia of the synchronous compensator, the duration of fault, and the speed of recovery
of the dc link. This may be a guideline for the decision about the size of the synchronous compensator to be
installed (see also Clause 2 and Clause 9).
Figure 4-15 illustrates constant frequency control.
Po
MW
G(s)
Po0 +
AC
net
work
1
Po
f2
AC
net
work
2
Figure 4-15ÑConstant frequency control of an island ac network
4.12.3 Power/frequency control
DC transmission can be used to assist the existing power generation station in controlling the frequency of
the network by modulating the transmitted power in proportion to the frequency deviation. It is often stated
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
in such cases that a dead-band for the frequency deviation shall exist. The gain of the regulator as well as the
gain of the dead-band are normally variable.
Figure 4-16 shows an example of a controller arrangement in which the power/frequency control unit generates an additional power order DP to a manually set order Po.
Po0
9 9 0
Po
+
+
Po
f
K
Dead
Band
Setting
Gain
Setting
Figure 4-16ÑPower/frequency controller
If required, the regulator can be so designed that its characteristic is similar to a turbine governor as illustrated in Figure 4-17.The control function has a variable static feedback (speed droop) giving a resulting
transfer function:
1
1
DP ( S )
--------------- = ----- ´ ----------------------bp
Ty
Df ( S )
1 + s æ -----ö
è b pø
(15)
with
Ty = response time of the pilot servomotor
bp = permanent feedback (speed droop)
When bp is set to zero,
DP ( S )
1
--------------- = -------Df ( S )
sT y
(16)
i.e., we have obtained constant frequency control according to the preceding paragraph.
4.12.4 Stabilization of an ac interconnection by a parallel dc link
When two ac systems are interconnected by parallel ac and dc links, the latter can be used to stabilize the
interconnection to a degree that is not possible with ac systems alone.
In Figure 4-18, two ac networks are interconnected by two ac lines and one parallel dc line.
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f
1
sTy
b
Po
p
Figure 4-17ÑTurbine governor power/frequency control
Here it is important that the phase angle difference
Dd = d1 Ð d2
(17)
between the two ac networks does not exceed a critical limit for the interconnection to be stable. The critical
limit may be reached when the load in one of the networks is suddenly changed or when one of the two ac
links is lost. If DPL corresponds to a load increase in the receiving ac network [Equation (15)], this network
decelerates. If one ac link is lost, ac network 1 accelerates and ac network 2 decelerates.
P1
Pa.c.1
AC
network
f 1U
1
1
1
Pa.c.2
Pd.c.
AC
network
2 U
f2
2
2
Figure 4-18ÑStabilization of an ac link by a parallel dc line
If, in this case, the power order for the dc line is partly determined by a regulator that derives a power order
from suitable ac system quantities in the two ac networks or the two ac lines via a control ampliÞer with suitable dynamic properties, the interconnection may be stabilized.
The most probable quantities to be measured are the frequency deviations Df1 and Df2. The regulator derives
the power order from the difference between these two frequency deviation signals; i.e.,
Po = G(s) á DF(s) = G(s) á [f1(s) Ð f2(s)]
(18)
where G(s) is the transfer function of the regulator.
A possible alternative to the frequency may be the measurement of the power transmitted on the ac line as
this power is determined by the phase angle difference between the interconnected networks according to
U1U2
P = ------------- sin ( d 1 Ð d 2 )
X
64
(19)
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
In special cases, one of the two networks may be so large that its frequency is not affected by variations in
the power transmitted on the dc line. The situation is accordingly simpliÞed and the power on the dc line can
be modulated with regard only to the frequency of the smaller network.
The stabilization regulator is normally active only during transients; i.e., the static gain of the regulator is
zero. Further, to optimize the stabilization ability of the dc link, the gain of the regulator is made as high as
possible for the important frequency region in which the oscillation frequencies are found. Digital computer
simulations, using power system stability programs, are normally performed for the determination of an
appropriate transfer function.
This technique for stabilizing a parallel ac line by dc has been applied in the PaciÞc DC Intertie. Here oscillations in the parallel ac intertie are detected by measuring the power transmitted in the ac line and are, after
some Þltering, used to modulate the dc power. The latter is obtained by modulating the current order in the
rectiÞer only with a maximum amplitude of 3% of rated current, which guarantees that there will be enough
current margin, even at a reduction of the current.
4.12.5 Stabilization of isolated ac system by a dc link supplied from an isolated system
Where the dc link is supplied from an isolated ac system (e.g., a generating station) and feeds a complex ac
receiving system, the dc link can be used to provide damping widely over much of the receiving system. For
example, if the local receiving system has weak ac tie lines to a neighboring system, the two systems can
exhibit relative swings due to transients at a frequency often well below 1 Hz, at which machine damper
windings give poor damping. (See Figure 4-19.)
AC
network
2
f2
AC
network
3
2
AC
network
1
f1
1
Figure 4-19ÑStabilization of a weak interconnection within one of the ac networks
This is the case in the Manitoba system in Canada, where the natural swing frequency relative to
Saskatchewan is about 0.3 Hz, and the systems can actually exhibit negative damping (continuous oscillation) in some conditions without the Nelson River dc link. This was substantially improved by modulation of
the latter to provide strong damping. The method is based on a measurement of the change of absolute phase
of local busbar voltage. This has the advantage of requiring no telecommunication for its derivation and yet
can detect and damp prospective swings in many parts of the ac system.
In a more general case, there might be complex ac systems at both ends of a dc link; damping can be provided to both if damping signals are taken from each ac busbar. Of course, it must be accepted that any dc
modulation will affect the power in ac systems at each end of the dc link; however, the effect is usually
small, and usually control constants can be chosen so that both systems are well damped.
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4.12.6 Telecommunication requirements
For higher-level control, the capacity and speed of response of the telecommunication link are of importance.
Both of these properties depend on the bandwidth of the telecommunication link and the terminal interface
equipment. As an indication of the requirements, assume that the current order is to be transmitted alone on
one telecommunication channel. Modern remote control terminal equipment together with a 2400 Bd channel can handle a message with 11 information-carrying bits and a reasonable number of administration bits,
with a delay of about 20 ms. The delay in this case is highly dependent on the number of security bits
included. Eleven bits can be used to represent a current order with a resolution of 0.05%. Such a telecommunication link normally represents enough capacity for damping control, as the expected oscillation frequency
for a disturbed ac network is normally below 2 Hz. Sometimes, different types of information are combined
in one message, with the consequence that the telecommunication delay is increased.
For constant frequency control and power/frequency control, the capacity requirement on the telecommunication system is more moderate; as such, control can be made rather slow.
To avoid unnecessary telecommunication delay, the leading master control equipmentÑi.e., that part of the
master control system where the current order is calculatedÑshould be located in the dc substation nearest
to the controlled quantity. Or, if quantities in the two ac networks are controlled, the leading master control
equipment should be nearer to the more sensitive ac network.
4.12.7 Power system damping and frequency control without telecommunication
Temporary breaks of telecommunication must not be allowed to impair modulation-control functions. One
solution is to force the station in which the controlled quantity is measured to take over current control when
the telecommunication system fails, unless it is already in control. This situation occurs if the ac network
connected to the inverter is to be stabilized by damping control and the direct current is controlled by the
rectiÞer. In this case, the inverter is forced to take over current control and dc power is then determined by
the station connected to the ac network that has to be stabilized by frequency control. The current order in
the other station is determined by the measured current response and a margin that is added with suitable
sign. Figure 4-20 illustrates this case.
Ud
A
=
=
min.1 >
min o
min.0
With Telecommunication
Link
B
Without Telecommunication
Link
Id
Figure 4-20ÑBackup control without telecommunication
A simpler method, which does not rely on the derivation of the current order from the current response, is to
lock the control orders from the master control system in both substations when the telecommunication link
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fails, and then add the additional modulating order only in that station in which the controlled quantity is
measured. The order in the other station is continuously kept locked. In this case, the modulating order contribution must be limited to, say, 0.5 of the current margin. The current margin can be increased to provide
larger modulation signals.
4.12.8 Emergency power control
This is the name used for a type of stabilization control applied with success in a number of dc schemes,
including the Konti-Skan, Skagerrak, and Fenno-Skan transmission systems. The idea is that the transmitted
power is changed by a preset amount of megawatts with a preset rate of change as a result of a signiÞcant
change in an ac system quantity, usually the system frequency. Such a signiÞcant change is interpreted as an
indication that a large disturbance has occurred in the power system.
Several reference levels for the change in the system quantity can be usedÑin Skagerrak there are six levelsÑand the action from the emergency controller can increase or decrease the transmitted power, and also
the power ßow direction can be changed.
4.12.9 Inßuence on both ac networks of dc power modulation
It should be noted that modulation of the dc link power, in order to control an ac system quantity, affects
both the sending and receiving ac networks. This means, for example, that when oscillations in one ac network are damped by the dc link, the other network must accept the same degree of power modulation.
4.13 Control and protection considerations for back-to-back schemes
With only a few exceptions, all the principles of control and protection for point-to-point transmissions also
apply to back-to-back schemes.
With no dc line there is no requirement for dc side Þlters. Communication requirements for interstation convertor control are greatly simpliÞed with back-to-back schemes. There is no need for an interstation telecommunication system and associated backup when all convertor controls are located in the same building, as in
the case of the back-to-back schemes.
Load rejection overvoltages in the undisturbed ac network following a serious fault in the other ac network
can be more readily controlled in a back-to-back scheme, as there is no dc transmission line, and accordingly
no need for a minimum limitation of alpha to 100° as discussed in 4.11.1. In the back-to-back conÞguration,
the convertor connected to the faulted ac (rectiÞer or inverter) system, upon sensing a severe ac voltage drop,
can automatically block during the ac fault, form a bypass valve pair, and carry current fed from the
unfaulted side convertor. The convertor on the other side connected to the ÒhealthyÓ ac system can automatically be operated as a rectiÞer with valve commutation in the normal manner with a Þring angle alpha close
to 90° (in a TCR mode). With limited direct current (less than 0.5 pu), it can absorb a relatively high amount
of reactive power. By absorbing reactive power from the ac system, the convertor limits the ac overvoltage
during the fault. Point-to-point dc conÞgurations would require quick telecommunications to limit overvoltages in the preceding manner if the fault occurs in the rectiÞer ac network. This could theoretically be done,
but it is not advisable to rely on telecommunication for limiting ac overvoltages to a safe level.
Overvoltages can also appear on the ac systems when there is not an ac system fault, for example, due to a
sudden power reduction by the dc link, or due to changes within the ac system. Such overvoltages can be
limited rapidly by a TCR mode control loop that overrides normal controls; this must act on the inverter irrespective of which ac system has the overvoltage, with the rectiÞer continuing to control dc current.
The overvoltage, due to load rejection, can be controlled more reliably than with geographically separated
stations, by immediately tripping the ac Þlters connected to both ac networks.
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In summary, it can be stated that most of the control functions are easier to realize for a back-to-back scheme
than for point-to-point transmission. This can result in better performance if the basic conditions are equal in
other aspects.
4.14 Control and protection considerations for multiterminal schemes
That the conventional current margin control principle can be applied to systems with more than two terminals connected in parallel was demonstrated in 1963, by Lamm, Uhlmann, and Danfors [B57]. The main difference between the control systems for two terminal and multiterminal schemes is mainly found at the
master control level ([see [B57]). Control principles for multiterminal applications with other control characteristics have also been proposed.
The load ßow in a multiterminal system is not as simple as in the two-terminal system, and consequently a
number of control functions must be included in the master control, either for automatic action or for assistance to the operator. Examples of additional tasks in the master control of a multiterminal system are as
follows:
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Balancing of the power orders for the different convertor stations
Coordination of power order ramping
Balancing and distribution of current orders to the convertor stations
Coordination of power modulation
Controlling the direct voltage at one of the stations
Determining temporary load ßow for fast recovery after contingencies
Assisting the operator in determining the load ßow and dc system conÞguration after a loss of
components.
SpeciÞc requirements of individual schemes may call for other control functions to be implemented.
The protections that are concerned with individual main circuit components are basically the same for multiterminal and for two-terminal systems. Care must be taken for protections that involve actions that inßuence
the whole system. An example of such protection is the dc line protection that must be designed to operate
satisfactorily, even when no telecommunication is available.
In some cases, especially for meshed dc network schemes, it may be necessary to include in the protection
system a function that, by current change measurement in the dc system nodes, can identify a faulty dc line
section for fast disconnection. As mentioned, this is of special interest for meshed network schemes, because
in this case the power can reach all stations even if a line section is lost, and fast automatic line section tripping can be applied by using dc breakers.
The discussion above refers mainly to multiterminal systems with convertors connected in parallel to the dc
line. In the special case in which tapping stations have a very low rating compared to the main transmission,
probably less than 5% of the main transmission rating, it may be useful to connect them in series with the
main station. In this case, the direct current is the same through all convertors and the tapped power must be
controlled by a basic voltage control system that controls the voltage across the convertor bridge. The
amount of power that can be taken from such a tapping convertor is dependent on the current in the transmission and is low when the current is low.
4.15 Higher-level controller characteristics for dc schemes in operation
In this subclause, some examples of structures of regulators for higher-level control functions are presented.
Most dc transmission systems are provided with such control functions used for ac system stabilization by
modulation of the transmitted active power or the reactive power consumed by the convertor or for steadystate or transient control of ac system frequency by varying the transmitted power.
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4.15.1 The CU Project
In the CU dc system, a bipolar transmission with a rating of 2 ´ 500 MW, power is transmitted from a coalÞred turbine generator station in Coal Creek, North Dakota to Dickinson, close to Minneapolis, Minnesota.
The two convertor stations are interconnected by a meshed ac network.
The dc link is used to stabilize the ac network and the modulation power order is derived from frequency
deviation measured at both rectiÞer and inverter commutation buses.
The modulating power order is
DP m = DP mR Ð DP mI = H R ( S ) ´ D f R Ð H I ( S ) ´ D f I
(20)
where subscript R and I refer to rectiÞer and inverter, respectively. Here,
5000s
H R ( S ) = ---------------------------------------------------------( 1 + 1.59s ) ( 1 + 0.159s )
(21)
9000s
H I ( S ) = ------------------------------------------------------------( 1 + 0.531s ) ( 1 + 0.531s )
(22)
DPmI is sent by telecommunication from the inverter to the rectifier.
The power modulation control for the CU project was originally based on the frequency in the sending end
network, but it was later found that consideration must also be given to the receiving network frequency as
discussed here.
4.15.2 Itaipu
The Itaipu dc transmission project consists of two bipoles with two 12-pulse convertors connected in series
in each pole and with a pole voltage of 600 kV. It transmits 6300 MW from nine 700 MW, 50 Hz generators
in the Itaipu hydroelectric plant to the 60 Hz Brazilian ac network with the inverters located in the Sao Paulo
area. Paraguay, with its 50 Hz network, presents a small local load in the Itaipu end of the transmission.
The Itaipu project is provided with three types of modulating controls. A control for reactive modulation of
the inverter acts on the g reference. It has a transfer function from ac network voltage to g modulation
equal to
2
49.3s
H ( S ) = -----------------------------------------------------------------------------------------------------------------------degree ¤ puvoltage
( 1 + 0.482s ) ( 1 + 0.318s ) ( 1 + 0.08s ) ( 1 + 0.053s )
This controller is not always in operation because it is not always needed. In fact, it was found in practice
that the network did not need voltage stabilization and the g modulation regulator has been disconnected.
The active power is modulated by frequency controllers for both sending and receiving ac networks.
The dc bipoles are the only loads of importance for the 50 Hz Itaipu generators, and the transmission links
must assist in controlling their frequency.
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For the receiving 60 Hz system, the dc transmission is provided with a power/frequency control function
with adjustable gain (similar to droop setting in a generator station). At a signiÞcant control action from the
sending-end 50 Hz controller, the 60 Hz regulator is put in hold position.
The structures of these controllers are presented in Figure 4-21. The block diagram refers to one bipole
(1 pu = 3150 MW).
f
60
f1
f2
1
+
1
r
-
sT1
P
60
Hold
-f3 +f3
K1
f
50
1
f4
1 + sT2
f 1 = -f 2 = 0.05 Hz
f 3 = 0.2 Hz
f 4 = 0.4 Hz
K2
P
50
1 + sT3
1 + sT4
r = 5%
K 1 = 0.01 p.u./ Hz
K 2 = 0.86 p.u./ Hz
T1 =
T2=
T3=
T4 =
1.5 s
0.1 s
1.0 s
5.0 s
Figure 4-21ÑItaipu frequency controllers for 50 Hz and 60 Hz networks
4.15.3 The intermountain power project (IPP)
The IPP dc system transmits power from a generating station in Utah to the Los Angeles area in the United
States. The dc link, which is rated 800 MW per pole (500 kV and 1600 A), can be in a radial conÞguration
with the generators, but an ac load in the form of outgoing lines can also be connected. Thus, a frequency
control function is used in the sending-end side.
The frequency controller conÞguration is different for radial operation and operation with an ac system connected. Figure 4-22a is the one used in radial operation with an integral part included. As indicated, the integral part is located on the bipole hierarchical control level with a proportional part in each pole.
When the ac network is connected, a proportional controller with dead-band according to Figure 4-22b per
pole is used.
4.15.4 The Gotland transmission
The Gotland transmission system was extended during 1987 to a bipolar transmission with a total rated capacity of 260 MW feeding the island of Gotland. The maximum service power at present is limited to 165 MW.
The island normally has no power generation of its own but synchronous compensators with a total capacity
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(Pole 1 Control Level)
f
U
+
-f1
f
f
+
1
P
o1
To Pole 1
Power Order
(Bipole Control Level)
f
U
K1
s
f
(Pole 2 Control Level)
f
U
-f1
f
f
+
+
1
K 1 = 500 MW/Hz.s
K2 =
500 MW/Hz [
500 MW/Hz [
f] > f 1
f] < f 1
P
o2
To Pole 2
Power Order
(K 2 could be adjusted)
f 1 = 0.3 Hz
a. 4-22aÑIPP
Sending end
generators
in radial
connection
Figure
frequency
controllers
for sending
end ac networkÑ
sending end generators in radial connection
f
U
f
P
o
-f1
f
1
To Pole
Power Order
K 2 = 500 MW/Hz
f 1 = 0.3 Hz
b. AC Network connected
Figure 4-22bÑIPP frequency controllers for sending end ac networkÑ
ac network connected
of 196 MVA are connected close to the convertor. The H factors for those compensators are 1.7 (70 MVA), 2.5
(77 MVA), 1.7 (30 MVA), and 0.8 (19 MVA), which, according to 2.3, gives Hdc = 2.3 (see Clauses 2 and 9).
A frequency controller of PID type is included in the dc control system. It has the following transfer function:
K
DP
G ( s ) = ------- = K 1 + -----2- + K 3 S
S
Df
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where
K1 = 30 MW/Hz
K2 = 27 MW/(Hz á s)
K3 = 20 (MW á s)/Hz
At the start of the transmission with the de-energized ac network, a diesel engine accelerates the 30 MVA
synchronous compensator, disconnected from the ac network and the other compensators, up to 30 Hz. Then
the dc link is deblocked and takes over and increases the speed up to 50 Hz. During this interval, only the
proportional part of the frequency regulator is in operation. However, the transmitted power is limited to
around 3 MW during acceleration, and the link acts as a constant power source until the frequency is close to
50 Hz. The other compensators are electrically started after 50 Hz has been reached and some load has been
connected.
4.15.5 Other projects
In Grund 1981 [B41], the control systems for the following North American projects are presented:
a)
b)
c)
d)
e)
f)
g)
David A. Hamil DC Tie (the Stegal back-to-back tie)
PaciÞc DC Intertie
Square Butte DC System
Nelson River Bipoles 1 and 2
Vancouver Island DC System
Eel River Back-to-Back DC System
CU DC System (original version)
The Cabora Bassa dc transmission between Mozambique and South Africa is discussed in Goosen and
Becker 1975 [B40].
4.16 Protection
There are only a few protection aspects of interest with reference to ac/dc interaction. For instance, for the
setting of parameters such as delay times, operation times, and detection levels for the dc protection, there is
often a need for coordination with the ac side protection. For the case of the detection (delay) time for a persistent commutation failure, the convertor tripping must be set with consideration of the settings of ac side
line protection. A serious ac system fault must not be interpreted as a permanent valve fault that produces
commutation failures. Thus, the delay time to convertor blocking from such a protection must be longer than
the time during which a fault in the ac system can exist until the faulty part is disconnected by ac protection.
The same applies to a possible simple dc side undervoltage protection that is designed as a backup for the dc
line protection to detect a ground fault on the dc side. The delay time to blocking from this type of protection
must also overlap the delay time of ac line protection, as serious faults in the ac system also cause low voltage on the dc side of the dc convertor.
In a few cases, the ac network impedance has some importance for the functioning of dc protection. One
such case is the commutation failure protection and its need to make a fast detection of a faulty valve. A permanent valve fault is a very rare event and can, from the practical point of view, only affect one six-pulse
bridge at a time. If the ac network to which the convertor is connected has a high SCR, disturbances generated by the faulty bridge will not cause a commutation failure in other bridges. A fast identiÞcation of the
faulty bridge by the commutation failure protection is possible. On the other hand, if the ac network has a
low SCR, the original valve fault may cause commutation failures in the other bridges. Accordingly, the
commutation failure protection delay time must be long enough to let the ac side protection to disconnect a
supposedly faulty ac branch, and a permanent valve fault cannot be identiÞed until this possible fault in the
ac network has been disconnected.
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Another aspect to consider here is the inßuence of the ac transmission on ac line protection close to the dc
convertor station. This protection is designed to measure sinusoidal voltage waveforms and can be disturbed
by a high content of harmonics. As long as the ac network has a high SCR, the amount of harmonics in the
voltage waveform is normally not critical for the ac line protection.
However, when the network impedance is high, the harmonic current generated by the convertor at asymmetrical ac system faults will disturb the ac voltage considerably. This may cause incorrect operation of the
ac line protection. The short-circuit level and fault current distribution of the ac network, possible harmonic
resonance, etc., are important factors in this case. The choice of the type of protection to be used should be
considered, and sometimes additional Þltering of the input signals should be applied.
5. Resonances, instabilities, and harmonic transfer
5.1 Introduction
All practical electrical circuits and networks have natural frequencies of oscillation or resonances, and dc
schemes are no exception. It is also true that in active circuits involving control systems, these resonances
may contribute to potential instabilities in any system.
Another feature of many electrical devices (for example, synchronous machines), is that a certain frequency
appearing at the terminals of a device will be transferred through the device and may appear as side-bands or
transferred harmonics in some other part of the system. In machines, this feature contributes to subsynchronous torsional interactions. This feature of harmonic transfer also occurs on dc schemes, with the convertors
acting as modulators. Frequencies that are present on the ac side of a convertor will be transferred through as
side-bands to the dc side, and vice-versa.
It is clear, therefore, that what might appear to be separate phenomena of resonance, instability, and harmonic transfer are in fact interdependent, and have thus been included in Clause 5.
5.2 Basic concepts
In an examination of resonances and related problems, there are several basic concepts that must be deÞned
and explained. This is particularly so when control loops are involved in the phenomena. A brief explanation
of these concepts is, therefore, given here. A more detailed understanding will be found in Ekstrom 1986
[B25], Jotten et al. 1978 [B50], Knaak and Venne 1987 [B54], Yacamini and DeOliveria 1980 [B87], and
Yacamini and DeOliveria 1986 [B88].
5.2.1 Loop instability
This type of instability is the classical type of instability that is described in standard control texts. This will
in general Ògrow from nothingÓ and can occur at any frequency, either integer or non-integer, both on the ac
and dc sides (non-integer will, of course, be more common). This can happen even in a perfectly balanced
system with no extraneous injection.
In dc schemes that are connected to ac power supplies of a Þxed frequency, it is useful to consider instabilities at frequencies both higher and lower than the ac system fundamental frequency, the so-called subsynchronous and supersynchronous frequencies.
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At subsynchronous frequencies, typically in the range from 5Ð40 Hz, one may encounter a conventional control instability that can be cured by suitable choice of control loop gain and other parameters. The behavior
in this frequency region also inßuences mutual effects, including possible instabilities, with shaft torsional
resonances in nearby machines.
An instability that occurs at a supersynchronous frequency has been loosely described as a Òharmonic instability.Ó In general, it starts from a non-integer frequency, nearly always close to a resonance; however, it can
lock into the nearest harmonic frequency as instability amplitude grows. This has been generally cured by
use of the phase-locked oscillator (equidistant-Þring) type of control system.
5.2.2 Harmonic magniÞcation
It can be shown that, viewed from the ac terminals, a dc convertor appears substantially as a source of harmonic current. This is true for both characteristic harmonics; i.e., those of order n = kp ± 1 where k is an integer and p the pulse number, and also for noncharacteristic harmonics. The effective impedance in which this
current ßows is that of the complete system comprising the ac system, capacitors, cables, Þlters, machines,
loads, reactive compensators, etc. Because the system is current-fed, the worst case will be when the impedance is a maximum. This will be characterized by a maximum in the impedance versus frequency curve.
For ac systems with SCR lower than three, the principal (i.e., lowest) resonance frequency approaches the
second harmonic. For SCR equal to two, the resonance may even be below the second harmonic.
The exact resonant frequency will of course be a function predominately of the ac system Thevenin equivalent impedance (inductive) and the ac Þlters that are capacitive at all frequencies below their lowest resonant
frequency.
It should be noted that not only the magnitude but also the phase angle of the impedance will be signiÞcant
at any given frequency.
All long-distance dc transmission schemes have dc lines or cables that, with dc reactors, exhibit various resonances. Because a convertor can be considered (approximately) as a voltage source at its dc terminals, it is
the minimum impedance on the impedance versus frequency curve for the dc system that is signiÞcant, as this
will lead to a high harmonic current. Again, any calculations must consider both characteristic and noncharacteristic harmonics; in this case, the characteristic voltage harmonics are of order n = pk. The impedance
phase angle should again be considered in any calculations at a given frequency. The existence of the ÒremoteÓ
dc station will have little effect at twelfth harmonic and upwards for a long line or cable scheme, but for lower
frequencies (e.g., fundamental or second harmonic), it can have a strong effect. The concept of ÒresonanceÓ
for the dc system in isolation is therefore not valid, and studies must always include both dc stations.
In addition to the generation of characteristic harmonics convertors may, under some circumstances, generate all other harmonics. Among the reasons for this are the following:
a)
b)
c)
d)
Unbalanced Þring pulses due to control system errors
Unbalanced impedances; e.g., ac system, Þlters, transformers, and untransposed lines
Harmonics from other sources both on the ac and the dc sides, such as other convertors, machines,
static compensators, and loads
Saturation of convertor transformers or other nearby transformers
Since harmonic resonances can exist on either side of the convertor, it follows that each of the prime sources
as above may be subject to magniÞcation on either the ac or dc side of the convertor.
The distinction from instability, in this case, is that effect is proportional to the cause, and if the cause (e.g.,
an extraneous EMF in an ac system) vanishes, then so does the effect.
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5.2.3 Harmonic transfer through convertors
A dc convertor acts as a modulator to harmonics. If a harmonic exists on the ac side of a convertor, it will
transfer this harmonic through the convertor, giving side-band harmonics on the dc side. For example, a second harmonic voltage on the ac side will give fundamental and third harmonic currents on the dc side. Similarly, a dc side harmonic will transfer through to the ac side as side-bands. For example, fundamental
frequency on the dc side will give dc and a second harmonic on the ac side (valve windings). This modulation is also true for non-integer harmonics in both directions.
It follows, therefore, that the ac and dc systems are effectively coupled at both integer and non-integer frequencies; this coupling must be accounted for in all calculations. The substantial coupling that can occur
through the dc system, as in back-to-back schemes, or in long line schemes at low frequencies (below third
harmonic), effectively extends all the way from one ac system to the other, via the dc link.
5.3 Harmonic resonance-related instabilities and solutions
In the introduction it was suggested that any problem associated with resonances and instabilities might be
inßuenced by several factors. These can include ac or dc side resonances, harmonic ampliÞcation, transfer of
harmonics through--convertors, the generation of harmonics by other plants, and non-theoretical harmonic
generation. In addition, any problems encountered may also be affected by such parameters as control loop
transfer functions and the saturation of convertor transformers or other local transformers. It is, therefore,
often difÞcult to deÞne exactly which parameters are dominating the effects seen in practice; this makes
groupings and classiÞcations difÞcult.
The following groupings are made with this in mind. The changes that were made to controls and plant to
alleviate these problems are also described.
5.3.1 Core saturation instability
Chronologically, the Þrst harmonic instability to be described that was not a simple loop instability was the
so called Òcore saturation instability.Ó This particular problem involved the mild saturation of the convertor
transformers by a small amount of direct current on their secondary sides. Problems have since been experienced on other schemes that have also involved the saturation of the convertor transformer. The mechanism
of the instability is different in each case, but they are grouped together here because of the common element
of core saturation. To date, this type of problem has been experienced on four systems; namely, the Kingsnorth, Nelson River, New England, and Chateauguay schemes. A more detailed explanation of each problem
is given below with the attempted solutions. Another feature of this type of instability is that there may be
Òcomplementary resonancesÓ on the ac and dc side of the convertors. In some schemes this has proved to be
the major driving force. These schemes have, therefore, been grouped together under the next grouping of
complementary resonances also.
If a dc system is resonant at an integer harmonic frequency then it may possibly be susceptible to core saturation instability. The system does not in fact have to be exactly on resonance at an integer harmonic.
Depending upon the Q factor of the system, a Ònear resonanceÓ will also give the type of problems discussed
here. In this type of phenomena, which can occur with a single-sided resonance or with complementary resonances (the latter being potentially more vulnerable), the source of the harmonic excitation is a saturated
convertor transformer that supplies all integer harmonics to the system.
There are two ways in which this type of instability can be excited. The Þrst, which is a true instability in that
it will start from an inÞnitesimally small excitation, occurs when a dc scheme that has a second harmonic ac
resonance is excited by a second harmonic of very small amplitude. One of the possible results of such a magniÞcation, as described previously, is that the ac fundamental will exist on the dc side of the convertor. This
fundamental on the dc side will in turn produce dc and the second harmonic on the valve winding side of the
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convertor transformer. The dc component will saturate the transformer, producing (among other frequencies)
the second harmonic, which will further contribute to magniÞcation, and thus force the system into instability.
The original small excitation then becomes irrelevant and the instability is now driven by the new source of
excitation, namely the saturated transformer. This type of instability is characterized by a slow build-up of harmonics taking perhaps seconds or even minutes. The slow build-up is a function of the manner in which dc
builds up in the transformer secondary winding and the ac system. Examples of this type of instability have
been reported on at least four schemes to date.
The second type of core saturation instability is similar but cannot start spontaneously; i.e., it is stable in the
steady state until the transformers are suddenly excited by a transient. The system will then jump relatively
suddenly to the steady unstable mode. This requires a large transient in the ac system such that the convertor
transformers can become saturated. Three examples of this type of excitation are (1) energization of the convertor transformer producing inrush current, (2) blocking of part of a multipolar scheme producing an overvoltage and hence transformer saturation, and (3) commutation failure producing transformer saturation.
When the transformer is saturated in this way there is always the danger of harmonic resonances causing
harmonic ampliÞcation of temporary overvoltages (this is discussed in Clause 4). A second consequence
might be the induction of core saturation instability as described. The saturated transformer can excite resonances with the ac and dc systems leading to a build-up of harmonics on both sides of the convertors. This
type of instability has been reported on at least two schemes.
In principle, core saturation instability can be cured by a suitable choice of a control system and its associated frequency response. However, this can lead to control parameters that are unsuitable at other frequencies; e.g., subsynchronous. Hence, for minimizing core saturation instability while avoiding subsynchronous
difÞculties, an auxiliary loop can be placed in parallel with the main control.
Two versions of auxiliary control have been used. The Þrst was used in the Kingsnorth and Nelson River
schemes. These schemes both exhibited fundamental frequency resonance on the dc side. In these schemes,
second harmonic components of primary magnetizing current are measured, demodulated to dc, passed via
control integrators, and then remodulated to ac by multiplying variable fundamental frequency waveforms
(from valve winding currents) to inject back into the main control.
The second method was used in the 2 ´ 500 MW back-to-back link between the Hydro-Quebec and New York
Power Authority systems at Chateauguay, which has a second harmonic resonance on the New York ac side.
The solution adopted was to process the measured fundamental component on the dc side to obtain a modulation signal that, when applied to the rectiÞer controls, counteracted the dc fundamental component. This sufÞciently reduced the dc component in the inverter transformer secondaries to eliminate second harmonic
build-up in the inverter ac system. The inverter control was left running on equidistance pulse spacing.
5.3.2 Complementary resonances
If a resonance exists or the impedance is high on the ac side at, say, the second harmonic and, at the same
time, a resonance (or low impedance) exists on the dc side at fundamental frequency, there is the possibility
that this could lead to a harmonic problem.
Suppose that a small amount of second harmonic exists on the ac side. This will transfer through as fundamental and the third harmonic on the dc side. The fundamental dc side voltage feeds the low dc side impedance, giving a current on the dc side that includes a fundamental frequency component. This fundamental
component will, in turn, cause a second harmonic and a dc component to be generated on the ac side. This
now sees a high impedance because of the ac side resonance, giving a higher component of second harmonic
on the ac side. This will add to the second harmonic that was already thereÑthis is the classical feature for a
harmonic build-up. In a more general form, if the dc resonance is of low impedance near a frequency f, and
an ac system high-impedance resonance is near (±f ±fo) where fo is ac system frequency, then the resonances
are complimentary. This type of build-up has been reported on at least three schemes.
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To date, two schemes have been reported as having experienced complementary resonances that were of an
integer nature.
One case of non-integer complementary resonance has been reported from the Nelson River scheme, where
the ac system natural frequency was 153 Hz. Following deblocking, a sustained 93 Hz oscillation was measured on the dc side. This was studied and found to be associated with a ground mode resonance on the dc
side of 93 Hz. This was solved by a simple control that introduced damping at the appropriate frequency.
5.3.3 Harmonic coupling between ac systems joined by dc links
In general, dc schemes are asynchronous ties, either joining systems of the same nominal frequency or systems of different frequencies (the exception being systems with parallel ac lines). The dc interconnection is
either a long overhead line, or a dc cable, or of zero length (a back-to-back scheme). On the dc side of the
convertor, a range of harmonic voltages are generated in addition to the desired dc voltage; the principal
components are generated in addition to the desired dc voltage; the principle components are of order 12k,
where k = 1, 2, 3... for a normal 12 pulse dc scheme. These voltages will cause currents of a low amplitude to
ßow on the dc side and hence to the convertor at the other end. This convertor will transfer the harmonics
through as side-band frequencies. These side-band frequencies are non-integer if the two systems are asynchronous. The resulting currents thus injected into the ac systems are of very low value and will, in the
majority of cases, be insigniÞcant and virtually undetectable.
In order to give guidance on the problem, typical Þgures have been extracted from Jotten. Let the two system
frequencies be f1 and f2. Then, assuming 12 pulse convertors, the frequencies of cross-modulation torques in
each system are at frequencies of 12k (f1 Ð f2) where k = 1, 2, 3, . . .
Consider a typical example. If a dc link connects two systems that are at the same nominal frequency and if
the system frequencies differ by up to 0.75 Hz, then torsional oscillations will be generated on the shaft of
both connected ac systems at frequencies of 9 Hz, 18 Hz, 27 Hz, etc. These are in the frequency range where
turbo alternator shafts could be put at risk.
Back-to-back schemes are probably most at risk from this problem because of the close intercoupling of the
terminals. With long dc transmission lines and cable systems, the cross-modulation should be reduced by the
line capacitances and inductances.
The two exceptions to this conclusion are where there are resonances with a high Q factor in the ac system.
These could take two forms, either electrical or mechanical. If an electrical resonance exists at one of the
corresponding real frequencies, a harmonic magniÞcation will take place. The Q factor of an electrical resonance is unlikely to be very high, hence this effect will not usually be important.
The second form of resonance, a mechanical resonance, may be more signiÞcant. Such a resonance with a
very high Q factor exists in alternators in thermal sets and to a lesser extent in hydrogenerators. This is the
torsional shaft resonance caused by the large masses on a turbo-alternator shaft and the extremely low associated damping.
A modulation frequency generated by dc cross-modulation could coincide with one of the shaft torsional
natural frequencies when transferred through the electrical generator, (again as modulation side-bands).
Then a build-up of torsional oscillations could occur in the turbo-alternator shaft, perhaps leading to shaft
fatigue problems and damage. This phenomena is similar to the torsional oscillation described in Clause 6.
The mechanism of build-up is, however, different. To date, no reports have been received of cross-modulation causing shaft damage. The implications of such a problem, however, are large, and it is recommended
that turbo-alternators that may be at risk should be monitored.
In considering this problem it should be emphasized that the amplitudes of injection harmonics are very low.
However, it has been reported (Fick 1982 [B31]) that an excitation of only 350 kW at a low frequency
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caused a 720 MW alternator to be put at risk in one scheme involving a slip energy recovery system in a
power station. A slip energy recovery system under these conditions is electrically identical to an asynchronous dc scheme.
It has been suggested by The Electrical Transmission and Distribution Reference Book [B26] and Woodford
et al. 1983 [B84] that a level of 0.1% of cross-modulated injection might be possible, which is about twice
that of the example previously given.
5.3.4 Harmonics and static var compensators
SVCs both of the SR type and the TCR type can be considered as sources of harmonics on an ac system.
All of the previous arguments about the excitation of harmonic resonances and the production of noncharacteristic harmonics under unbalanced systems will apply. Any harmonic studies that are carried out on a simulator or computer program should include the effect of SVCs.
On the Chateauguay scheme, when the problem on the dc system had been controlled by modulating the rectiÞer, it was found that operating restrictions could not be removed completely because a similar problem
occurred with the controls of the static var compensator located on the same inverter bus.
The manufacturer of the SVC will also be implementing a control solution to the problem.
In the meantime, Hydro-Quebec wanted to increase its export capacity to the full capacity of the single
765 kV line to New York. Load-ßow studies of the New York system indicated that in order to achieve this,
an additional 270 Mvar of reactive power compensation would be required at Chateauguay. It was decided to
install this in the form of two 135 Mvar damped second harmonic Þlters.
Although not strictly required to resolve the control problems, these Þlters were seen to have the advantage
of essentially eliminating second harmonic transient overvoltages and therefore reducing arrester stresses. At
the same time, these second harmonic Þlters will permit the existing operating restrictions to be removed for
the critical peak load period in the winter of 1988/1989. When the SVC control solution is implemented,
tested, and accepted it is expected that there would be no need for the existing operating restrictions, even
without the second harmonic Þlters.
5.3.5 Parallel ac/dc transmission lines
If a dc line runs in parallel with an ac line in the same right-of-way or if an existing ac line is converted to dc,
then fundamental voltage will be induced on the dc side.
It might be thought that control action could also be used to eliminate the problem. This is not necessarily
the case. The fundamental frequency EMF induced on the dc line will cause a fundamental frequency component in the dc line, if control actions are disregarded. This will produce transferred harmonics on the ac
side that will include dc and the second harmonic. This dc component will saturate the convertor transformer
and reinforce the already-generated second harmonic. To complete the steady-state higher harmonics, the
sidebands of the theoretical harmonics will also be present.
It is possible, by control means, to reduce or eliminate the fundamental frequency component on the dc side
by modulating the convertor Þring angle using the type of feedback circuits used on Chateauguay to cure
core saturation instability.
However, in practice, this is not an ideal solution, because the modulation of alpha in a fundamental frequency pattern gives both dc saturation of the convertor transformers and high amounts of harmonics on the
ac side. Thus, nothing is gained by using controls in this particular case, and measures such as the provision
of Þlters on the main circuit must be taken.
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5.4 Factors inßuencing harmonic problems
The factors that will affect the harmonic magniÞcation and harmonic instabilities described previously
include the following:
a)
b)
c)
d)
e)
f)
g)
h)
i)
j)
k)
High impedance resonances on the ac side
Low impedance resonances on the dc side
Complementary resonances
AC system voltage unbalance (negative sequence)
AC system impedance unbalance
Extraneous frequencies from the ac system
Extraneous frequencies from the dc system (normally originating in the remote ac system)
Coupling from an ac line to a dc line
Convertor control system unbalance errors
Transformer saturation
Control feedback
5.5 Trends and sensitivities of system parameters
The parameters that will have the biggest inßuence on harmonic resonances on the ac side are the strength
(impedance) of the ac system, its impedance angle, and the size of the harmonic Þlter. On the dc side, the
size of the dc reactor, the presence of dc Þlters, and the inductance and capacitance of the line will dominate.
As a guide, the lowest parallel resonance frequency on the ac side can be found approximately from:
f ( res ) = f 1 S ¤ Q c
(23)
where
f1
S
Qc
is the fundamental frequency
is the short-circuit capacity of the ac system in MVA
is the size of the Þlter and shunt capacitor bank in Mvar
provided the resulting value of f(res) is well below the lowest tuned Þlter frequency.
In a typical dc scheme, Qc is normally dimensioned to compensate fully for convertor var consumption Qd.
Qd normally has a value between 0.5 and 0.6 of dc power, Pd. For Qc = Qd = 0.5Pd, the above equation can
be expressed in terms of SCR as follows:
f ( res ) = f 1 S ¤ 0.5P d = f 1 2 × SCR
(24)
For the conditions assume the resonant frequency will be equal to the second harmonic for SCR = 2.
Once the system impedances have been decided, the trends and sensitivities will be dominated by the controller as described previously.
5.6 Methods of study
There are at present basically three methods of carrying out the type of study needed to solve the problems
described.
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The Þrst method uses the HVDC simulators (physical models). These are suitable for the study of largeamplitude disturbances.
The second method consists of time domain studies by computer. Computer packages, such as the electromagnetic transient programs, have been specially designed for this use.5
The third method of analysis uses frequency domain methods.
The type of study carried out will vary depending partly on the problem to be solved and partly on the availability of study tools.
5.7 Different types of schemes and harmonic problems
For types of schemes other than point-to-point transmissions, the underlying mechanisms and physics are
the same. In the following subclauses, only those aspects that are speciÞc or of special importance for the
other types of schemes are discussed.
5.7.1 Back-to-back schemes
These have a relatively restricted dc system, usually comprising only a dc reactor. The effective dc system
loop impedance is that of the dc reactor plus summed commutation reactances plus transferred ac system
impedance effects. In some cases, no dc reactor is used; the remaining effects ensure that effective loop
impedance is still substantial.
At subsynchronous frequencies the effective ac loop impedance is low, which is a substantial advantage for
stability at such frequencies. For avoidance of core-saturation instability, the absence of fundamental frequency resonance on the dc side is an advantage, though back-to-back schemes have still exhibited core-saturation instability due to near-second-harmonic resonance on the ac side. At low-order harmonics, the usual
harmonic effects are generally not much different from long-line schemes. However, there is a substantially
greater harmonic transfer effect from one ac system to the other, so that, for example, a negative-sequence
fundamental component in one ac system goes through a double transformation to contribute a small amount
of negative sequence fundamental and third harmonic to the other ac system.
5.7.2 Multi-infeed schemes
For multi-infeed schemes, the harmonic interaction not only takes place through the convertors, but also
through the ac network. The complexity of the situation is thus enhanced. In order to analyze the risks for
adverse interaction, all dc schemes that are electrically close must be considered. It is possible that the performance when each scheme alone is in operation is acceptable; however, operation with two or more dc
systems gives unacceptable performance if no corrective measures, in the control or by equipment, are taken.
5.7.3 Multi-terminal schemes
The considerations concerning harmonic resonances for multi-terminal schemes are basically the same as
for point-to-point transmission and multi-infeed schemes if ac coupling exists between the terminals. But,
due to the complexity of the dc side system in multi-terminal schemes, there may be more harmonic resonances on the dc side. A careful design of dc Þlters is necessary also with regard to the choice of their location and the smoothing reactor values so as to meet Þlter performance requirements.
It is also obvious that a number of operating conÞgurations exist, and a careful analysis of all these are necessary.
5Examples
80
of widely available proprietary software of this kind are EMTP, EMTDC, NETOMAC, SPICE, and SILVER LISCO.
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5.7.4 Low- and zero-inertia systems
For a dc infeed into a low- or zero-inertia ac system, a synchronous compensator is used on the inverter side.
Besides providing the necessary commutation voltage or enhancement of the existing ac system strength, the
synchronous compensator partly compensates for the reactive power consumed by the dc convertor. This is
generally similar to more conventional schemes, except that the ac system impedance viewed from the convertor is dominated by the synchronous compensator and may be relatively high.
5.8 Comments
In several of the schemes built to date there have been harmonic problems at some stage of development. In
most cases, these problems have been overcome by additions to the controllers. The additional control circuits are relatively inexpensive, especially if considered early in the design stage of a project. Thus, careful
consideration should be given to the possible need for such circuits.
6. Subsynchronous torsional interactions between dc convertors and
nearby turbine-generators
6.1 Introduction and summary
The potential for subsynchronous torsional interactions between a dc transmission system and nearby turbine-generators was Þrst experienced during Þeld tests at the Square Butte DC System in North Dakota. This
dc system employs a supplementary frequency-sensitive power controller (FSPC) to damp out low frequency electromechanical oscillations between the sending end and the receiving end systems. Prior to the
test, it was suspected that the FSPC had enough residual gain to stimulate torsional oscillations in one of the
generators at the sending end.
The test conÞrmed that the FSPC did interact and destabilize the Þrst torsional mode of one of the units
(11.5 Hz). To the surprise of everyone, however, it was also found that the dc current control acting without
the FSPC was enough to destabilize the Þrst torsional mode upon loss of one of the ac transmission lines.
Thus, it was observed that dc control systems can interact with a turbine-generator rotor and exert a destabilizing inßuence on a torsional mode of oscillation, even in the normal mode of control without supplementary damping signals.
Field modiÞcations were initially made that allowed stable operation under limited conditions. These were
immediately followed by an analysis of the interaction that led to control system modiÞcations that allowed
stable operation under all but extreme system contingencies.
Following this development, the Electric Power Research Institute (EPRI) initiated a research project to
investigate this phenomenon and to develop generic solutions (EPRI EL-2708 [B28]). In the project, it was
found that negative damping to turbine-generator torsional modes of oscillation is inherent to the objective
of controlling current in a dc transmission system. Some degree of negative damping will exist within the
bandwidth of this current control, and torsional vibrations at frequencies higher than the bandwidth of the
current control will experience positive damping. This was the case with the CU dc system in North Dakota,
which was extensively tested in the summer of 1979. The CU dc system is located adjacent to a power plant,
for which the turbine-generator units have a Þrst torsional mode frequency of 19 Hz, considerably higher
than the 11.5 Hz of the unit near Square Butte. This 19 Hz frequency was just beyond the range of negative
damping caused by the current control.
The outcome of the EPRI research project has also shown that the interaction is sensitive to many system
parameters, most signiÞcantly, ac system strength, dc power, and the control mode of the dc system. Maximum
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interaction occurs with the weakest ac transmission system, especially in the limiting case of an isolated turbine-generator whose only load is a dc convertor. It has also been shown that special dc power modulation control for damping electromechanical modes of system oscillation can cause signiÞcant subsynchronous
torsional interaction and may require appropriate control Þltering to limit the interaction at critical torsional
frequencies.
One method to mitigate the torsional interaction is by varying the frequency range and magnitude of the negative damping associated with the rectiÞer current control loop. This can be achieved, within a fairly limited
range, by modifying the characteristics of the current control loop. Otherwise, a supplementary damping
control device may be required to assure torsional stability of all units in the area.
The methodology for designing a supplementary subsynchronous damping control (SSDC) was developed
under the EPRI project, and its performance and robustness have been demonstrated by both digital computer programs and dc simulators. Such a controller would ensure net positive damping contributions to torsional modes of oscillations for all turbine-generators in the vicinity of the dc system. The project also
developed practical guidelines in determining the need for an SSDC in dc systems.
In this subclause, the considerations involved in deciding whether to add subsynchronous damping control
are discussed, along with considerations for turbine-generator protection against torsional vibrations. Inasmuch as the solution to the torsional interaction consists of a control modiÞcation, adopting such a solution
has only a minor impact on overall system costs and should have no inßuence on decisions with respect to
location and ratings of major equipment.
6.2 Description of the phenomenon
Turbine-generator rotor motion causes variations in both magnitude and phase angle of the ac voltage supplying the convertor. The effect on convertor Þring angle caused by an angular shift in the voltage waveform
is illustrated in Figure 6-1. For the equidistant Þring angle control, utilized in modern dc systems, a shift in
voltage phase, f, causes an equal shift in the apparent Þring angle, a, away from the steady-state pre-shift Þring angle, a¢. The apparent change in Þring angle, as well as variations in the voltage magnitude, will result
in changes in direct voltage and current, and thereby dc power transfer. Meanwhile at the terminal, a closed
loop control on direct current, direct voltage, or Þring angle would respond to correct for these changes,
thereby impacting the magnitude and phase of variations in dc power transfer. The ultimate effect of the
change in dc power is a change in the generator electrical torque. If the accumulated phase lags between the
change in the generator shaft speed and the ultimate resulting change in electrical torque on the generator
rotor exceed 90°, the torsional oscillations may become unstable.
6.3 Principal parameters
The ability of a dc system to impact torsional oscillations of a nearby generator unit is, of course, dependent
upon the relative size of the dc system compared to the unit, as well as the electrical distance from the convertor to the unit. dc transmission from a remote, somewhat isolated power plant would likely interact with
the generator torsional modes, while a dc interconnection of relatively large networks may not be prone to
this condition.
Based on the results of the EPRI research project, the inßuence of dc control on torsional damping of a particular generator can be quantiÞed by unit interaction factor (UIF) as the following:
MW dc
SC g
UIF g = --------------- = 1 Ð ----------MVA g
SC tot
82
2
(25)
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V ac after a phase shift of
Vac prior to phase shift
(normal steady state)
Firing pulse
a
a
a
a
a
= Actual firing angle following shift in Vac
= Steady-state firing angle before shift in Vac
= a +
Figure 6-1ÑEffect of alternating voltage phase shift on Þring angle
with equidistant Þring control
Figure 6 1
where:
UIFg
is the unit interaction factor of the generator
MWdc is the rating of the dc system
MVAg is the rating of the generator
SCtot
is the short-circuit capacity at the dc commutating bus including the generator
SCg
is the short-circuit capacity at the dc commutating bus excluding the generator
For unit interaction factors less than about 0.1, there is very little interaction between the dc controls and the
turbine-generator torsional oscillations. Hence, an SSDC would not be required to solve a potential destabilization problem, nor would an SSDC signiÞcantly enhance the torsional fatigue loss-of-life of the generator.
It is noteworthy that the subsynchronous torsional interaction phenomenon is particular to steam turbinegenerators. Hydraulic turbine-generators do not experience the same kind of problem. It has also been found
that only units near a rectiÞer terminal are vulnerable to torsional interactions. The units near an inverter terminal do not experience much destabilization. This is due to the fact that rectiÞers and inverters react differently to phase angle variations. In addition, it would be unlikely to have network situations with units weakly
connected to the ac system at the inverter end of a dc transmission link. If there were turbine-generators near
the inverter terminal, one would normally expect that there would be load in the area sufÞcient to provide
damping for subsynchronous oscillations.
It should also be noted that another possibility for adverse torsional oscillations in nearby units has been
mentioned in the literature (see Stemmler 1987 [B74]). This possibility has been surmised from a design
consideration in the Þeld of variable speed drive systems, in which care must be taken to avoid excitation of
various oscillatory modes in associated mechanical systems by harmonics generated by the electrical conversion systems. In dc system applications, the transfer of harmonics from one end of the dc link to the other
may possibly result in steady-state oscillations that could excite torsional modes of nearby turbine-generators. Such a phenomenon has not been observed to date; nevertheless, its possibility is fully discussed in
5.3.3 of this guide.
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6.4 Trends and sensitivities of system parameters
During the Þeld tests at the Square Butte facility, it was found that the instability of the torsional mode of
oscillation depended on the power level of the dc line and upon the number of ac transmission lines in service. Either reducing the dc power level or closing in another transmission line was found to eliminate the
instability. This was conÞrmed by analytical results that matched measured test conditions. Figure 6-2 and
Figure 6-3 show families of curves where ac system strength and dc power level, respectively, are varied for
the simple parallel ac/dc system of Figure 6-4.
X AC = 0.1
Electrical Damping (pu)
X AC = 0.2
X AC = 0.35
10
X AC = 0.75
0
X AC = 10.
-10
-16
.4
1. 2.5 6.3 16. 40.
Torsional Frequency (Hz)
Figure 6-2ÑPlot of electrical damping versus torsional frequency for several levels of ac
system strength, XAC á PDC = 1.0 pu
Electrical Damping (pu)
P DC = 0.1
P DC = 0.5
10
8
6
4
2
0
-2
-4
.16
P DC = 0.75
P DC = 1.0
.4
1.
2.5
6.3 16.
40.
Torsional Frequency (Hz)
Figure 6-3ÑPlot of electrical damping versus torsional frequency for several levels of ac
system strength, XAC á PDC = 1.0 pu
Figure 6 3
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Rectifier
IEEE
Std 1204-1997
Inverter
R
XAC
Figure 6-4ÑSimpliÞed system representation for sensitivity studies, XAC/R = 7
The destabilizing effect of the dc system increases as the parallel ac system weakens, since as the ac system
becomes weaker, the inherent positive damping of the ac system diminishes and the coupling between the dc
line and the turbine-generator increases. Hence, the worst case in terms of torsional interaction with dc systems is the maximum dc power with the weakest conceivable ac system. As a point of reference, the turbinegenerator located near the Square Butte terminal became torsionally unstable when the negative damping
contribution exceeded 2 pu at the torsional frequency of 11.5 Hz. It can be seen from Figure 6-2 that for
rated dc power transfer in a nearby radial conÞguration (XAC = 10 pu), the negative damping contribution is
in the neighborhood of 10 pu at 11.5 Hz, thereby creating an unstable condition.
The nominal Þring angle at which the rectiÞer operates also has a substantial inßuence on the damping effect
of the convertor. Operation at relatively large nominal Þring angles would tend to increase the destabilizing
impact of the convertor. This is an important consideration for dc links that are required to operate at a
reduced direct voltage where both the rectiÞer Þring angle and the inverter extinction angle are increased
above their nominal steady-state values. Such operating modes may thus drastically increase the negative
damping effect of the convertors at torsional frequencies.
Other factors impacting the torsional interaction are the gain and time constant of the exciter and the power
system stabilizer, if any, on nearby generators. It has been observed on the Cross-Channel Link that a very
small time constant of generator speed measurement would result in a reduced electrical damping at critical
torsional frequencies. Increasing the measurement time constant to effectively reduce the speed loop gain at
torsional frequencies would solve the reduced electrical damping problem.
6.5 Inßuence of dc controls
The interaction observed at the Square Butte project occurred through two different control paths: FSPC and
the current control. In the case of FSPC, the interaction was due to high gain and large phase lag in the lower
range of the subsynchronous torsional frequency region. Only one of the units near the rectiÞer terminal had
a torsional frequency low enough to interact with the FSPC. The Þrst torsional mode frequency of the other
unit was high enough so that a negative damping interaction did not occur. Thus, for this situation, notch Þltering of FSPC at 11.5 Hz was an effective and appropriate method of eliminating interaction through that
control path. A double notch Þlter with frequencies staggered about the torsional frequency of 11.5 Hz was
installed. Tests showed safe operation of FSPC for all system conditions.
Solution of the torsional instability through the current control path was not quite as easy. In fact, analysis
showed that negative electrical damping to turbine-generators near rectiÞer terminals was inherent to the
objective of controlling dc current, resulting in a degree of negative electrical damping over some frequency
range. The analysis also showed that torsional oscillations at frequencies higher than the bandwidth of the
current control will experience positive damping. This was the case with the CU dc system for which the
nearby turbine-generator units have a Þrst torsional mode frequency of 19 Hz, considerably higher than the
11.5 Hz of the unit near the Square Butte dc tie.
Although it may not be possible to totally eliminate the negative electrical damping, it is possible to minimize the magnitude of the interaction at the frequencies at which the negative damping occurs. This
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approach was taken at Square Butte, for which analysis showed that the dc current regulator could be
adjusted to maintain torsional stability for all anticipated system operating conditions without degrading the
response of the dc system. The control system was modiÞed accordingly, and subsequent Þeld tests showed
that the changes resulted in stable operation.
6.5.1 Subsynchronous damping control (SSDC)
The SSDC concept developed in EPRI EL-2708 [B28] consists of a wide bandwidth controller sensitive to
generator speed if available, or to the frequency of an ac signal synthesized from voltage and current measured at the dc convertor terminal. With such a design, the SSDC can be made to provide a positive damping
contribution over the entire range of subsynchronous torsional frequencies, as indicated in Figure 6-5. This
Þgure represents the damping inßuence of an isolated turbine-generator whose only load is a dc convertor.
For this particular system, negative damping exists up through 30 Hz without an SDCC, but with the SSDC,
the damping characteristic changed to positive damping for frequencies above 5 Hz.
5.0
Electrical Damping, D e (pu)
4.0
3.0
2.0
With SSDC
1.0
0.0
-1.0
-2.0
No SSDC
-3.0
-4.0
-5.0
1
10
100
Torsional Frequency (Hz)
Figure 6-5ÑImpact of practical SSDC on electrical damping
Such a control was tested on a dc simulator. The conÞguration consisted of a turbine-generator unit connected solely to a dc transmission system. The turbine-generator unit had two torsional modes at 13.5 and
22 Hz. SigniÞcant test results demonstrated that an SSDC can be built to provide positive damping to torsional vibrations over a wide frequency range. Very little modulation of the system is required.
Another method of damping torsional oscillations is to modulate the Þring instant with a suitable phase and
amplitude with regard to the generator oscillations. The input signal for this modulation can be derived
either from the speed of the generator or from the bus frequency. In the case of using the generator speed as
the input signal, the only required signal processing is to pass the signal through a bandpass Þlter to eliminate the low intermachine oscillation frequencies and the high-frequency noise. Considerable positive damping contributions may be achieved in the subsynchronous torsional frequency range with such a damping
method. However, in some applications, it may not be possible to use such a wide bandwidth damping controller. In these situations, it might be possible to focus on one torsional mode at a time by using bandpass
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Þltering techniques. Bibliography entry no. 13 indicates that in case of the bus frequency as input, in order to
overcome the inherent delay associated with the frequency measurement, the signal is passed through a narrow bandpass Þlter tuned to one torsional frequency. Therefore, positive damping may only be provided for
that particular torsional frequency.
The Þrst consideration in applying an SSDC is whether it is needed to solve a potential problem associated
with dc destabilization or whether it can signiÞcantly reduce fatigue damage per event on adjacent turbinegenerator units. The research results have indicated that units near an inverter terminal are not likely to suffer
destabilization; indeed, for some combinations of torsional frequencies and dc control characteristics, the
inverter control action actually improves the damping somewhat as compared to a pure ac transmission system. Thus, only units near a rectiÞer station need to be considered.
6.5.2 Impact on planning for systems with dc transmission
Planning for the location and size of major transmission and generation facilities should not be inßuenced by
concerns over the existence of the dc torsional interaction phenomenon. Major equipment items can be chosen and cited for optimum economics while considering advantages of dc power control in steady-state and
transient stability characteristics of the transmission system. The only inßuence of torsional interaction control is a potential side beneÞt by reducing fatigue duty on the turbine-generator shaft. This is a contrast to the
problems associated with series-compensated ac transmission systems, where the SSR interaction can limit
the amount of power transfer through an ac line or require additional pieces of major equipment to allow
higher levels of compensation. The torsional interaction with dc systems can be mitigated relatively simply
by including appropriate controls with a negligible impact on the overall cost of the system.
After the major equipment has been chosen, studies should be initiated to determine the need for an SSDC.
Preliminary screening studies involving UIF calculations should be conducted for all conceivable system
contingencies. Results of this screening study are often sufÞcient to determine whether an SSDC should be
included in the equipment speciÞcation. Since the interaction is dependent upon the exact characteristics of
the controls, detailed studies should await vendor selection.
6.5.3 Turbine-generator protection
Protective relays are available to protect against turbine generator instabilities caused by the transmission
network. For example, relays have been applied to each of the Coal Creek turbine generators, near the CU
HVDC system, as a backup in case of control system failure, which could cause torsional instability. These
relays use generator speed as an input to detect torsional oscillations and trip the associated unit when oscillations become excessive.
It should be noted that SSDC is not a protection device. It is simply a control device that allows stable operation in situations where, because of torsional interactions, it was not possible to operate. Thus, it is prudent
to provide protective torsional relays to any nearby unit that may adversely interact with the convertor.
6.6 Methods of study
The combined ac/dc system can be visualized in block diagram form as shown in Figure 6-6. It is instructive
to open the loop shown in the Þgure at the electrical torque feedback point and to calculate the transfer function from generator rotor speed, DwG, to electrical torque, DTe, which consists of effective damping and synchronizing coefÞcients as
DT
w
----------e- ( jw ) = D e ( w ) Ð j -----b- K e ( w )
Dw G
w
(26)
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Te
Machine and AC/DC
Power System
(Electro-Mechanical)
Rotor Torsional
System
(Mechanical)
G
b
s
G = Per Unit Generator Speed
= Generator Rotor Angle
Te = Electrical Torque
b = System Base Frequency
Figure 6-6ÑConceptual system diagram
where
De
Ke
w
wb
is the effective damping factor due to electrical system
is the effective synchronizing factor due to electrical system
is the frequency of oscillations
is the system base frequency
The electrical system will be producing positive damping if the real part of the above transfer function, De, is
positive. In other words, the electrical damping will be positive if, for a positive (or negative) change in the
generator shaft speed, the resulting change in the generator electrical torque will also be positive (or negative), so that it will oppose the change in the shaft speed.
It should be noted that without the electrical damping contribution, a torsional system has inherent positive
damping due to steam ßow, friction, windage, and losses due to shaft twisting, which can be lumped together
and termed mechanical damping. A torsional mode will become unstable when the electrical damping contribution is negative and exceeds the mechanical damping contribution. Therefore, comparison of the De versus frequency curve, for a speciÞc machine, with estimated values of mechanical damping, is an indication
of relative stability of torsional oscillation modes. An example is shown in Figure 6-7. Such a De versus frequency plotting approach is very informative when utilized in sensitivity studies, since it readily provides an
indication of damping on other modes of oscillation that may exist in the system. Furthermore, the results
can be related to modiÞcations in the frequency response characteristics of the control systems.
Another method for investigating the damping effect from the convertor on the nearby generators is to incorporate an electronic model of the turbine-generators in the dc simulator setup of the system. It would then be
possible to modulate the shaft speed of the machine and measure the momentary amplitude and phase of the
dc power; i.e., the electrical power on the rotor when the convertor is the only load for the generator (isolated
operation). Comparison of the dc power with the momentary speed of the rotor would yield the complex transfer function from rotor motion to dc power. The real part of the transfer function, for each frequency, would
then be a measure of the damping contribution from the convertor on a torsional oscillation at that frequency.
There is yet another method suggested in the literature for interaction analysts. This method is based on
modelling the convertor and its control as an equivalent admittance, valid for a particular combination of
network conÞguration, torsional frequency, and level of series compensation. The convertor equivalent
admittance is then combined with those of other system elements to arrive at the net impedance of the system viewed from a given generator, which subsequently can be used for torsional interaction analysis.
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De
Stable for all
Torsionals shown
0
-Dm
1
2
3
Torsional
Frequency (
)
First Torsional at 1 shown to be
-Dm
unstable since De ( 1 )
Figure 6-7ÑCurves of electrical damping, De, versus torsional frequency, w, showing
stable and unstable modes of oscillation
Figure 6 7
7. Transient, steady-state, low-frequency, and power-frequency stabilities
7.1 Introduction
A number of phenomena occurring in ac systems fall under the general classiÞcation of stability. The particular areas that will be considered hereunder include power system steady-state and low frequency stability,
power system transient stability, and power frequency stability. There are other types of instabilities that are
particularly connected with dc convertors, such as harmonic instability and core saturation instability. Subsynchronous instability and voltage instability can also occur in ac and dc systems. These types of instabilities are discussed in other clauses of this guide.
7.2 Descriptions of stability types
The following descriptions of stability types [B50] apply to electrical systems in general and are applicable
to systems that include dc links.
a)
b)
Transient stability of a power system. A power system is transiently stable for an aperiodic steadystate operating condition and for a particular disturbance, if, following that disturbance, it reaches an
acceptable steady-state operating condition. This is generally taken to mean that, for example, for
loss of a line, no generator or load has to be disconnected.
Steady-state stability of a power system. A power system is steady-state stable for a particular
steady-state operating condition if, following small disturbances, it reaches a steady-state operating
condition that is identical or close to the pre-disturbance operating condition. This is also known as
small disturbance stability of a power system.
Transient stability is a characteristic of an ac system and is concerned with the electromechanical stability of
machines subsequent to a disturbance.
For transient stability there are indirect effects caused by the interaction between a dc link and machine
behavior. An ac fault near a dc inverter will cause a collapse of inverter operation during the fault, hence loss
of power infeed for this time. The machine will swing as in any ac system, but the Òmegawatt secondÓ shock
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can exacerbate machine behavior. After the fault is removed, the dc power will not recover instantly; the
recovery time depends on the dc line, the characteristics of the ac networks, and the control system design. It
is usually essential to minimize convertor recovery time to prevent the undue increase of the megawatt second shock, and hence possible transient instability between ac system machines. Recovery time is usually
longer when the ac system has a low or very low SCR relative to convertor rating.
Steady-state stability is the response to small disturbances. With constant demand and generation, a system
could be said to be in a Òsteady state,Ó but in practice, the system is continually subjected to small disturbances arising from changing demand, generation output, and voltage conditions. These small disturbances
require the system to move continually from one steady-state condition to another. As in all dynamic systems, the movement from one steady-state condition to another involves some oscillation prior to settling to
the new condition. In an ac system, these oscillations are damped by machine damper windings and loads.
Damping of such oscillations can be improved by using power stabilizer signals on machine voltage regulators, and by the use of supplementary damping controls on dc links.
However, inter-area swings involving weak tie-lines may be at such low frequencies (as, for example,
0.15 Hz) that damper windings have little effect. Negative damping from various causes has been known to
produce continuous oscillations (low frequency or dynamic instability). As in the case of transient stability, a
dc link with basic controls does not directly affect this type of instability, due to its much higher natural frequency, but with proper action by supplementary controls, system damping and stabilization can be
achieved.
When studying the different types of instabilities of an ac/dc system, it is very important to Þrst consider the
stability of the convertor with basic controls (refer also to Clause 4); this is particularly relevant in the case
of very low SCR systems.
Power frequency stability refers to the frequency conditions of the ac system as a whole. Power frequency
stability can be described in terms of steady-state and transient stability, but, in this case, it is applicable to
generator groups within a system. A steady-state or oscillatory instability can occur, leading to variations in
system frequency in the case of governor hunting. This is relevant, for example, where an isolated generating
station feeds only a dc link. To assist speed control of the generator, the dc control would require a characteristic responsive to system frequency such that the dc system load on the generator has a response like that of
an ac system. Some form of frequency feedback should be employed to achieve this characteristic.
The transient form of power frequency instability can occur when a receiving system relies relatively heavily
on infeed via dc. If system frequency and voltage fall too low, for example, during a transient disturbance,
then the system may collapse if the dc input power cannot supply the load power under relevant conditions.
Generator governors will operate to control overspeed, but fast dc link control action in the form of dc power
increase or generator tripping may also be required if the overspeed presents a problem.
7.3 Main parameters and effects
The main parameters inßuencing the stability of interconnected systems and their effects are as follows:
7.3.1 Transient stability
a)
b)
c)
90
Type and location of fault, method and time of fault clearance, and change in system conÞguration
due to fault clearance all affect the angle to which synchronous machines swing during the fault, and
consequently the synchronizing power required to restore synchronism.
Pre-fault power ßow in ac lines.
System inertia also affects the angle to which synchronous machines swing.
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d)
e)
f)
g)
h)
IEEE
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SCR affects the ability of the dc link to recover after fault clearance. There is no direct relationship
between SCR and machine swing, as a low SCR system may have a high inertia, and vice versa. ac
machine recovery is a function of fault infeed from the machine terminals. Recovery is thus a function of the ac system impedance rather than ac/dc interaction.
Machine angle swings that occur subsequent to fault clearance are consequent voltage swings (to a
relatively low magnitude) that may cause inverter commutation failures several cycles after an
apparent successful recovery. This condition is accentuated in cases of low SCR.
In a var compensation system, both synchronous and static compensation affect system voltage and
recovery subsequent to faults.
The rate of power recovery affects stability, because after relatively long ac system faults, fast recovery may cause voltage instability at the inverter bus of a low or very low SCR system due to the temporarily depressed ac system voltage seen by the inverter. In this case, a slower rate of recovery may
be desirable.
DC recovery from faults is dependent on a number of additional factors including protection and
control sequences, such as voltage-dependent current order-limits (VDCOL), temporary blocking,
ac voltage waveform distortion due to transformer saturation (magnetizing inrush current) harmonic
impedance, and settings of dc current recovery ramp rates.
7.3.2 Steady-state and Low-frequency stability
a)
b)
c)
d)
Network and generation conÞguration can cause instability because the problem of poor damping
will normally occur between plant/demand groups that are electrically far apart, particularly when
there is a heavy exchange of power between the two groups.
SCR affects the stability of the ac voltage during normal operation. Stability is improved by higher
values of SCR.
Amount and type of reactive compensation can result in instability, as both synchronous and static
compensation may interact with link controls. Link and associated equipment (e.g., SVC) controls
that in themselves are stable, may in combination provide unstable or oscillatory operating modes.
Also, constant power control contributes to poor damping where the dc link represents a large part of
the ac load. This may lead to machine governor hunting unless an extra frequency damping control
loop is added.
Type of load can affect stability, as loads generally exhibit variations of real and reactive power as a
function of voltage and frequency. These characteristics can affect system damping modes.
7.3.3 Power frequency stability
The same factors that inßuence transient and steady-state stability also inßuence frequency stability. An
additional factor is the output of machines lost after a fault as a proportion of total system demand. The
higher the proportion, the more likely the occurrence of power frequency instability.
7.4 Trends and sensitivities of system parameters
The most important parameters that inßuence both steady-state and transient stability of synchronous
machines are generally applicable to ac systems and not conÞned to dc links. These include system inertia,
fault clearance times, and automatic voltage regulator and governor controls, and are therefore not discussed
here.
System fault level affects machine stability and link recovery. In particular, low SCR systems will require
longer recovery times to ensure that ac voltages are maintained at satisfactory levels.
A SC(s) increases the inertia of the system and its SCR, thereby assisting in system voltage control. If the
link terminal is electrically remote from the rest of the ac system, it can in principle have transient instability
problems of its own. Under disturbed conditions a SC can introduce new oscillation modes. This has to be
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considered when studying low-frequency stability but is of course no different from that of adding a new
generator in a purely ac system. Consideration also has to be given to the modulation of the ac voltage resulting from these oscillations. Where a dc link supplies an isolated load without local generation, but supported
by a SC, its inertia and ratio of compensator rating to link rating are important to its stability (see Clause 9).
The SC should be appropriately sized (reactances and time constants) to mitigate the voltage modulation
problem when it is used to support a weak ac system.
In cases assessing the effect of machine swinging on the modulation of ac busbar voltage, the SC can oscillate with combined dominant and hunting modes that are a function of the inertias and impedances.
Static compensation does not increase the ESCR but assists in voltage control subsequent to fault clearance
by controlling the overvoltages.
DC control strategy affects system recovery. One strategy is to try to recover power as fast as possible. However, the corresponding reactive consumption tends to reduce the ac voltage. Recovery may not be achieved
for a system having a very low SCR unless some temporary limitation is put in the dc current magnitude by
the control strategy. Another strategy involves temporary blocking of the inverter if the fault voltage falls
below a certain level. After fault clearing, the convertors are deblocked and the current ramped up according
to a set rate. This strategy generally may enable smooth restoration but will extend the recovery time.
For a low SCR system, the utilization of modulation of real and/or reactive power can be a valuable asset for
enhancing system performance. The criterion for aiding system performance in some conÞgurations may
consist of the transfer of real power of the proper magnitude and timing, while, in other cases, reactive power
control is more critical to overall performance. The tailoring of the dc system behavior to achieve the most
favorable overall ac/dc performance is an attainable system design objective.
7.5 AC and dc parallel operation
In the context of weak systems, addition of an ac line increases the strength of the ac system but the dc link
may improve performance of interconnected system through modulation.
7.6 Inßuence of dc control
7.6.1 Transient stability
Where system contingencies, such as faults, result in the reduction of transmission capability, a generation
source will usually accelerate. Remote sources may decelerate as load exceeds generation as a result of the
fault that decreases power into that area. Upon clearing the fault, the generation and the remaining transmission experience a transient swing and may approach instability. Very long fault clearance times can cause a
loss of synchronism prior to clearance.
If this loss of synchronism does not occur, in an ac/dc system where a dc link is connected to the generation
and a system load point, it has been found advantageous to increase the sending end dc link power in the
post-fault period in response to the increase of generator speed. This action will remove energy from the
generator, reduce its speed, and thus reduce the angular displacement between the generator and the ac
receiving system. The magnitude of the modulation applied for this purpose has been in the range of 20Ð
40% of the dc link rating. Systems have been designed with temporary overload limits as high as 65%; in
other cases, higher limits have been utilized for modulation consistent with the following provisions. The
level of modulation is a function of ac system power transfer need, ac voltage support (var) capability, and dc
system design. Similarly, for receiving-end phase angle or speed changes, dc link power can be controlled to
correct this condition within the limits imposed by the controllability of the receiving-end phase angle, the
dc link capability, and the energy that may be taken from the generation source.
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7.6.2 Steady-state stability
Conditions have existed wherein heavily loaded ac systems oscillate at a period of seconds and with insufÞcient damping to prevent buildup of the oscillations. If an existing dc link is connected to one or both buses
of the system experiencing a substantial angular swing, suitable control of the dc link can modulate the dc
power ßow in such a manner that damping is introduced to cause a decay in the system oscillations. The
magnitude of the modulation to achieve sufÞcient damping has been found to be of the order of a few percent of the dc link rating and is considered a small-signal modulation.
7.6.3 Power frequency stability
A generator or group of generators representing a small proportion of the total system capacity connected to
an ac system has its frequency controlled by the system. Where generation is not connected to the system by
ac lines, as in the case of generation connected through dc links only, or in cases of system breakup where
generation and load exist in islands, the governors are too slow and hence not effective in controlling system
frequency. By suitable control, the dc link response can hold the generation frequency within close limits
without reliance on the governors for this purpose.
7.7 Methods and tools for study
The complexity of calculations required makes it necessary to use computer programs. The method is to
include an appropriate dc link model within a standard ac transient stability or small-signal stability program.
7.7.1 Transient stability
a)
In the standard ac transient stability program, representation of real and reactive powers at the highvoltage busbar is a function of busbar voltage. This can represent normal and abnormal operation
(i.e., commutation failure), and the effect of changes in real and reactive power demand/infeed on ac
system machines can be addressed in the transient stability program. The dc is represented by a
quasi-steady-state model. This represents the convertors by steady-state equations allowing dc quantities to vary with time. These equations relate the rms ac quantities on one side with the average dc
quantities on the other. The control schemes can be represented by a Vd/Id characteristic or a series
of transfer functions.
b)
For time domain analysis, the solution is achieved by comparing instantaneous ac and dc values on a
three-phase basis using EMTP-type programs. The ac and dc network solutions are carried out separately and compared periodically to ensure agreement on interface quantities. The time steps
required for the dc solution are far shorter than those that would be used for the normal transient stability solution, and therefore, during this calculation, a Thevenin equivalent ac network is used. The
interface point should be chosen such that ideally the ac quantities are sinusoidal.
c)
Simulators can be used, but the accuracy of results is very dependent on the complexity and number
of machine models used.
7.7.2 Small-signal stability
a)
An analysis of steady-state oscillations can be made assuming that the response of the system is linear for small disturbances around a particular operating condition. This assumption enables a simpliÞed linear mathematical representation and provides an understanding of the capability of the
system to dampen such steady-state oscillations. The calculation of eigenvalues provides the oscillation frequency and degree of damping for each instability mode.
b)
Simulators can be a powerful tool in assessing control and ac system interactionsÑparticularly the
fast varieties.
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7.8 Different types of schemes
The previous discussion of transient stability was concerned with point-to-point dc transmission. Aspects of
transient stability relevant to back-to-back and multi-terminal dc schemes are discussed here.
A dc terminal interacts with the transient stability response of the ac system through:
a)
b)
Its ability to recover from disturbances (e.g., an ac fault) and to permit the ac system to re-establish
synchronizing power.
Fast changes of power followed by power modulation to improve ac system transient stability and
damping. Modulation of reactive power can be coordinated with the real power or the special
requirements of the system.
In general terms, the same considerations apply to back-to-back schemes and multi-terminal schemes. The
following are more speciÞc considerations.
7.8.1 Back-to-back schemes
Changes in power order do not require communication between terminals. A fast change in power to assist
the ac system can be implemented in minimal time, irrespective of which side of the station is controlling
current (or power). Also, small and large signal modulation can be applied without communication with full
local knowledge of both ac systems. Any coordinated modulation of real and reactive power is performed
with locally derived data from each ac system. The extent to which the faster response will be of beneÞt
depends on the ac stability margins. Should one of the ac systems have both low inertia (a faster transient
swing) and high impedance, a shorter time will be available for the dc system to provide effective assistance.
Fast dc power order changes can only be implemented once the convertors have recovered their operating
capability.
7.8.2 Multi-terminal schemes
Two factors will make greater demands on the multi-terminal performance.
a)
b)
The recovery of a terminal from ac disturbances can be expected to be more complicated because of
the possibility of transiently diverted dc current from unfaulted terminals. Interaction with the ac
system parameters together with the control response capabilities will determine whether a multiterminal case for transient ac swings will be more onerous than for an equivalent terminal rating in a
back-to-back scheme.
Power modulation and changes in power order, unless within overall margins, are implemented
through coordination of all terminals (different operating control characteristics leave room for this
problem to be minimized).
Should two or more of the multi-terminal stations terminate in the same system, power changes, modulation
and ac transient swings will be coupled by the common ac system. Thus, interaction with the ac system is
extended to ac interaction between terminals. This gives rise to common-mode disturbances for which the
recovery of more than one terminal is a consideration. Power order changes and modulation can be proportionally assigned to the terminals to provide the best performance.
A disturbance that causes a power interruption by dc voltage collapse in one inverter station when other stations are connected to isolated ac systems will also interrupt power ßow elsewhere. The nature of the local
interaction will determine the recovery performance after the disturbance is cleared at the remote station. In
this situation, the common mode coupling is via the dc system.
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IEEE
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8. Temporary overvoltages (TOVs)
8.1 Description of phenomena
Changes in the reactive power balance of the ac network initiated by switching, faults, or power ßow variation (in either ac or dc networks) produce changes in the operating voltage. Surplus reactive power can also
lead to voltage increases. Larger disturbances result in temporary overvoltages (TOVs). The term Òtemporary overvoltageÓ refers to the complete waveform that consists of the fundamental component and the possible superimposed oscillatory component.
On the busbars with close generator infeed, TOVs are reduced within a time constant that is in the range of
200Ð600 ms by the generator excitation system. In such networks, the possibility of self-excitation of generators after load rejection must be taken into account.
If generators are electrically distant from the convertor terminal, TOVs can be sustained for seconds; they
can only be reduced by switching network elements, use of (VCs, or special metal oxide (MO) arresters.
The dc station always consumes reactive power in the range of 0.5Ð0.6 pu of transmitted power. The amount
consumed depends on the commutation reactance and operating a and g, but is inßuenced only marginally
by the power ßow direction (rectiÞer or inverter). If the short-circuit capacity of the ac network is low relative to the dc power, a sudden change in the active power, and therefore also in the reactive power, or the
blocking of the dc due to a fault, may lead to high TOVs. These overvoltages inßuence the design and the
costs of dc stations.
For equivalent ac network strengths, TOVs in the rectiÞer mode are normally more severe than in inverter
mode, as the voltage drop of the active power on the ac network impedance produces an additional increase
of overvoltage.
Usually the loss of convertor real and reactive power occurs almost simultaneously in both dc terminals, and
TOVs occur in both stations. Only in the case where the temporary bypass operation mode is used by the
convertor control can the overvoltage be avoided in the non-faulted ac network.
TOVs can lead to saturation of the convertor transformer or transformers near the dc station. Normally, the
saturation effect reduces the amplitude of the fundamental frequency component of the overvoltage. However, if resonance conditions in the ac network are close to one of the lower-order harmonics, the overvoltage
can be ampliÞed. This is often the case when dc power is large compared to the short-circuit capacity of the
ac network, as the resonance frequency of such networks is low. Shunt capacitors connected to the convertor
bus for ac Þltering and reactive power compensation make conditions worse by further reducing the resonance frequency.
In the case of a fault in the ac network and subsequent blocking of the convertors, even higher overvoltages
can occur than at load rejection. At the recovery of the system, the voltage component, according to the resonance frequency of the network, is superimposed on the load rejection overvoltage.
When switching transformers, high inrush current can occur. If the harmonic components of this current
meet resonance conditions in the network, high harmonic voltages are superimposed on the operating voltage. This leads to TOVs that can last for several seconds.
Figure 8-1 shows an example of TOV at load rejection initiated by blocking the dc convertor. Figure 8-2
shows a TOV at fault clearing in the ac network when the dc remains blocked. The ESCR of the studied system was 1.8 pu. A TOV caused by transformer energization is shown in Figure 8-3.
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
Ua
Ub
Uc
Figure 8-1ÑTOV at blocking of dc transmission (SCR = 2.4)
Figure 8 1
Ua
Ub
Uc
Figure 8-2ÑTemporary overvoltage at fault clearing without restart of dc transmission
(SCR = 2.4)
Ua
Ub
Uc
Figure 8-3ÑTOV at convertor transformer energization (SCR = 2.4)
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TOVs on the ac side primarily inßuence the design of arresters on the busbar, and breakers, and through that,
the insulation level on the ac side of the dc substation. The stress on the valve side arresters in the station is
relatively low, as the voltage across the valves is reduced by factor of approximately 3 when the convertors
are blocked.
However, if the temporary bypass mode is used for faults in the ac network close to the convertor station, the
valve arresters can be stressed by the full value of the TOV after fault clearing.
At partial load rejection, such as load rejection in one pole of a bipolar dc transmission, TOVs are lower than
at full load rejection. But it should be noted that in this case the valves remaining in operation are stressed by
the full overvoltage, unlike the blocked valves. This type of overvoltage may be critical for an economic
valve design. However, overvoltages can be reduced via control action increasing active and reactive power
of the sound pole.
8.2 Main parameters affecting the phenomena
The main parameters inßuencing the TOVs are as follows:
a)
b)
c)
d)
e)
f)
g)
h)
Strength of the ac network (system impedance) related to the rating of the dc scheme. In addition to
the network impedance at the fundamental frequency, the knowledge of the impedance and angle at
lower harmonic frequencies for positive and zero sequence system is of importance. However, the
value and angle of the ac system equivalent impedance at the fundamental frequency can be used for
rough estimation of TOVs.
Reactive power consumption of the network, depending on the active power infeed into the network
as shown in Figure 8-4. This parameter inßuences the overvoltage component produced by the
change in active power.
Reactive power of the dc station deÞned by the commutating reactance, Þring angles, and the operating conditions.
Saturation characteristic of the convertor transformer and the network transformers close to the dc
station (to calculate harmonic currents at saturation).
Reactive power compensation equipment connected to the busbar of the dc station at the given operating conditions. Information is needed on size and conditions for switching compensation units.
ConÞguration of the dc scheme and of the ac network in order to analyze the possible faults and
switching operations leading to TOVs and to determine the most severe realistic case.
In the case where the generators are electrically close to the dc station, the data of turbo-generators
are important (primarily those related to the excitation and speed control systems).
Information on the use of additional measures for reducing TOVs; e.g., static var compensators, fast
switching of capacitor banks and ac Þlters, and MO arresters.
8.3 Trends and sensitivities of the system parameters
The most important parameter is the value and phase angle of the impedance of the ac network related to the
rating of the dc transmission. Regarding the TOVs, the network can be assumed to be weak if the fundamental frequency component of overvoltage at full blocking of convertor station exceeds value 1.3Ð1.4 pu. This
is the case at SCR = 2.5 to 3.0. At higher overvoltages (with weaker networks), additional measures for
reduction should be considered to keep costs of the dc stations within limits and to not endanger the voltagesensitive equipment in the ac network.
A further important parameter is the resonance frequency of the ac network seen from the ac busbar of the dc
station. If the resonance is close to the 2nd or 3rd harmonic, the overvoltage can be ampliÞed by the saturation phenomena.
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
U (kV)
Q (MVA)
200
245
230
100
220
PDC (MW)
-200
100
-100
200
-100
Figure 8-4ÑReactive power requirements of low and very low SCR system depending on
the active power loading (example)
The damping in the network plays an important role as it inßuences the amplitude of overvoltages and length
of their duration. The amplitude of the fundamental frequency component of TOV at an impedance angle of
90° is the same for the rectiÞer and the inverter. For lower angles in the range of expected values for the ac
network, the overvoltages reduce at the inverter and increase at the rectiÞer because of a more pronounced
voltage drop produced by the real power on the ac network impedance.
A reduction of the amplitude of TOVs produced by saturation can also be obtained by the use of ac Þlters
that provide damping at low frequencies of the order of second to Þfth harmonics. In this case, Þlters bypass
the harmonics produced by saturation that would ßow into the network and produce overvoltages.
8.4 Inßuence of dc control
The reactive power of a dc convertor station can be controlled by increasing the Þring angle and inßuencing
the consumption of reactive power. However, in this case the dc station must be designed for reactive power
and voltage control.
After a fault occurs in the ac network, with the resultant temporary blocking of the dc transmission, overvoltages can be limited if the dc restarts immediately. An increasing reactive power demand of the convertor at
restarting reduces the overvoltage. Nevertheless, for the design of equipment the most severe case must be
taken into account; i.e., when the dc fails to deblock, and the full overvoltage occurs.
The use of the temporary bypass operation mode for an ac system fault enables operation at reduced current
and increased Þring angle in the station connected to the unfaulted ac network. The reactive power demand
of this station remains nearly unchanged, and overvoltages can be avoided.
If a fault occurs in only one dc pole of a bipolar dc scheme, control can be arranged to increase active and
reactive power of the unfaulted dc pole to counteract the overvoltage.
8.5 Methods and tools for study
The estimation of the fundamental frequency component of TOV at blocking and also at fault clearing without dc restart can be done by means of a simpliÞed calculation. It can be conducted separately for each station as the inßuence of one terminal on the other can be neglected.
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Assuming the total ac system seen by the convertor is represented by a Thevenin equivalent and Þxed voltage infeed behind the impedance Z Ðf E , the overvoltage factor of the fundamental component of TOV kTOV
based on the initial steady-state voltage on the convertor bus is:
2
2
2
k TOV = [ 1 + 2Z ( P cos f E + Q sin f E ) + Z ( P + Q ) ]
1¤2
(27)
where
Z Ðf E is the total effective ac impedance, usually deÞned by ESCR = (1/Z) ÐÐ f E
P & Q is the real and reactive power drawn by the convertor
P
is the positive for rectiÞer, negative for inverter
Q
is the positive for rectiÞer or inverter
Quantities (P, Q, ac impedance) are per unit values; the base is usually the rated ac voltage and rated convertor real power.
Equation (27) applies exactly only if the solution is less than the saturation voltage of transformers on the
busbar, typically about 1.2 per unit of rated voltage. For higher values, the actual fundamental frequency
voltage component of TOV will be lower than given by the equation, accompanied, however, by harmonic
distortion components.
The reciprocal value of Z Ðf E , given in pu, represents ESCR and includes Þlters and capacitor banks on the
busbar. To Þnd this value from the system impedance Z s Ðf s with its reciprocal value representing SCR, the
following equation is valid:
1
1
-------------- = --------------- + jQ F
Z Ðf E
Z s Ðf s
(28)
where
1
--------------Z s Ðf s
is the admittance of ac system alone, excluding Þlters and capacitors
QF
is the total capacitive admittance of Þlters and capacitors
For the calculation, the fundamental frequency network impedance and angle and the reactive power compensation at the busbar of the dc station are used. The active and reactive power loading of the dc is dropped
to zero, and the corresponding overvoltage is calculated assuming the constant voltage behind the network
impedance. Figure 8-5 shows the system conÞguration for the calculation and the results of overvoltage factors for rectiÞer and inverter operation plotted against SCR, with the impedance angle of the network as a
parameter. The calculation gives the fundamental frequency overvoltage component only. The estimation
can, however, be used in the planning stages of dc projects.
It is possible to more accurately calculate the fundamental frequency component of the TOV following fault
clearing without restarting the dc system. The ac network must be simulated in detail, at least in the neighborhood of the dc station. The calculation can be done using a transient stability program, representing a
positive sequence system. The dc infeed can be represented by the active and reactive power loading that can
be removed when calculating an overvoltage at load rejection or at fault clearing. An example of such a
study where the network was simulated in detail and the generators were represented, including their complete excitation systems, is given in Figure 8-6.
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
Pd
Qd
Z/ s
Qc
1.8
REC,
= 75¡
1.6
REC,
INV,
INV,
= 85¡
= 85¡
= 75¡
1.4
K
TOV
1.2
1.0
1
2
3
4
5
6
SCR
Figure 8-5ÑSystem conÞguration and results of simpliÞed calculation for
overvoltage factor KTOV at blocking of dc over SCR assumptions:
Pd = ±1 pu, Qd =Figure
0.6 pu, Qc8.5
= 0.6 pu, ULO = 1.0 pu
System Configuration and Results of Simplified
1.0
U
1.0
Pd
0
150
300
ms
Figure 8-6ÑOvervoltage following dc load rejection calculated by stability program (the ac
network was represented in detail including excitation systems of generators) (SCR = 4)
Figure 8 6
However, this calculation doesnÕt take into account the transient component of the phenomena and the possible resonance conditions due to saturation. The results of such a study can be used for the design of most
equipment if critical resonance conditions are not expected in the ac network. They are, however, not suitable for the detailed study of the arrester stresses for insulation coordination or the determination of transient
voltage required for design of other equipment.
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For a detailed study, as necessary for the design of surge arresters, a three-phase representation of the ac network, using the corresponding network impedance at least up to the 4th harmonic, is needed. Depending on
the use of a control function for limiting TOVs, the dc should be simulated by either simpliÞed or by detailed
control representation. The saturation of the transformers should also be properly simulated in this case. The
study can be done by digital computers or by using an analog simulator. An example of such a detailed study
made on simulator is given in Figure 8-7. The dc is blocked at the fault on the ac busbar of the convertor station and remains blocked after fault clearing. The bus voltages, arrester currents in phases a and b, and the dc
power are shown in Figure 8-7.
Ua
Ub
Uc
I era
I erb
Pd
Figure 8-7ÑFault clearing with dc remaining blocked;
study of energy stress in the ac bus arrester (SCR = 2.2)
This detailed network representation must also be used when studying overvoltages and arrester stresses at
transformer energization. The example in Figure 8-3 shows the result of such a study.
8.6 Measures for the limitation of TOVs
In weak networks, TOVs caused by load rejection in dc systems can reach very high values. This has an
impact on the design and costs of the dc equipment and can also endanger other equipment in the network.
TOVs can be reduced, apart from convertor control, by such different means as the use of synchronous compensators (SCs), static var compensators (SVCs), metal oxide arresters, and the switching of shunt capacitors and ac Þlters connected to the busbar of the dc station.
8.6.1 Synchronous compensators (SCs)
Synchronous compensators (SCs) connected to the busbar of the dc station increase the SCR of the network.
The increase depends on the rating of the SCs and the sum of the subtransient reactance of the machine and
the reactance of the step-up transformer.
The TOVs are then reduced according to the increased SCR of the network.
The use of SCs solely for the limitation of TOVs would, however, be a very expensive solution owing to high
investment costs and high operating losses. Because of longer maintenance times and the higher outage
probability of SCs, one unit should be assumed to be out of operation when calculating the maximum TOV.
SCs should therefore be used only where reinforcement of the network is also needed, because insufÞcient
short-circuit capacity produces problems with other interactions and in low inertia systems.
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Sometimes SCs are connected to the tertiary of convertor transformers. However, in such a case, the possible
conÞgurations for load rejection must be studied. If, for example, the entire dc station is disconnected due to
a fault, the ac network experiences TOVs without the SCs becoming effective.
8.6.2 Static var compensators (SVCs)
The static var compensator (SVC) connected to the busbar of the dc station can contribute to the limitation of
TOVs by shifting the operating point by fast control into the inductive range. The inductive impedance of the
compensator connected parallel to the network impedance reduces the total effective impedance of the network and, through that, limits TOVs.
Because of the time constant of the SVC control, the reduction of the TOV is effective about two cycles after
the occurrence of the TOV.
The SVC, as a measure solely for the reduction of TOV, is an expensive item. However, if the SVC is needed
for ac voltage control during normal operation, it can be a competitive solution. The solution is especially
suitable if voltage control of the ac network and TOV limitation are also needed when the dc system is out of
operation and overvoltages can be limited by control action.
To reduce investment costs and losses when the SVC is used for TOV limitation, it can be built for low-rated
power during normal operation, but with a high overload capability for the short time of TOV.
The other possibility for limiting TOV by an SVC is by employing a saturable reactor connected to the busbar of the dc station. The advantages of this solution are a large short-time overload capability of the equipment and a response corresponding directly to the voltage increase. However, in many cases additional
elements must be provided in this type of SVC to adjust the saturable reactor to the operating voltage and to
ßatten the slope of the impedance in the saturation area. Problems may also arise from the additional production of harmonics, especially during asymmetrical fault conditions.
8.6.3 Metal-oxide (MO) arresters
The metal-oxide (MO) arrester offers an alternative solution to limit TOVs and can act alone or in conjunction with convertor control and the switching of shunt capacitors and ac Þlters.
The basic idea behind the use of MO arresters to limit TOVs at the convertor station is to exploit the high
energy-absorption capability offered by the MO equipment. Various solutions are possible. Two basic
approaches adopted in recent dc projects are discussed below:
a)
b)
102
MO arresters with an extremely low protective level are used to limit the TOV to values of typically
1.4 pu and permanently connected to the ac busbar. To achieve this low protective level and because
of the given MO material characteristic, signiÞcant currents ßow through the arrester at normal operating voltages. The arrester, therefore, needs special cooling to avoid overheating during continuous
operation.
The use of such permanently connected MO arresters is recommended where the initial two or three
peaks of the TOV are higher than the acceptable value and cannot be limited by other arresters
installed in the station.
Special MO arresters that are switched in by circuit breakers in the case of high TOVs. When the
TOV has been reduced either by restarting the dc system or by switching out the shunt capacitors
and ac Þlters, the arrester is disconnected from the network to prevent overloading caused by normal
operating voltage. This arrester can limit the TOV to values as low as 1.25 pu. However, the closing
time of the breaker must be considered with the result that the overvoltage is not limited until a few
cycles after its occurrence.
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In both solutions the possible fault contingencies must be studied carefully to determine the maximum
energy stress of the arrester. Lower protective levels require higher energy capability of the MO equipment
and consequently lead to higher costs. Experience shows that the optimum overall design could be in the
range of 1.25Ð1.4 pu.
8.6.4 Switching of shunt capacitors and ac Þlters
Shunt capacitors and ac Þlters used for reactive power compensation in the dc stations decrease the SCR on
the busbar, which is the main parameter inßuencing the amplitude of TOVs following load rejection. This
TOV can therefore be reduced if capacitor banks and ac Þlters are disconnected. However, in this case, the
circuit breakers for this equipment must be designed to switch off at maximum TOV. This means that breakers are usually one voltage level higher than in normal cases. When applying this measure for the limitation
of TOV, the corresponding opening time of breaker and a suitable strategy for back-up protection (e.g., a second breaker to disconnect the whole station) must be taken into account.
This solution leads to considerably higher costs for the ac switchyard. However, the switching of capacitor
banks and ac Þlters can provide other measures for the limitation of TOV and, in case of MO arresters, is an
essential part of the operating strategy.
8.7 Different types of schemes
The fundamental and general characteristics concerning TOVs are covered in the subclauses above. In this
subclause, only the aspects that are speciÞc or of special importance for other types of schemes, other than
point-to-point transmission, are discussed.
8.7.1 Back-to-back schemes
The fact that the rectiÞer and the inverter are in the same station is of importance. A properly designed control and protection system can, in principle, eliminate TOVs on the dc side, regarding both magnitude and
duration. The formation of by-pass pairs on the faulty side enables dc current to circulate, and the consumption of reactive power on the undisturbed side is maintained, resulting in voltage control.
In a back-to-back scheme, the two ac systems are more closely coupled to each other, especially concerning
harmonics, than in a line or cable transmission. The total impedance in the dc circuit is just the sum of the
leakage reactances of the convertor transformers and the smoothing reactor. As a consequence, harmonics in
the ac voltage appearing on one ac side can more easily be transferred to harmonic currents on the other ac
side via the convertors. Large negative sequence voltages that occur (e.g., as a consequence of single line to
ground faults), will give rise to third harmonic currents appearing on the other side. If no low harmonic Þlters are provided, the transferred harmonic currents might cause high TOVs of that frequency if the system is
of high impedance.
If low-order harmonic Þlters are installed, the third harmonic current can lead to high stresses in these Þlters.
The possibility of transferring harmonics from one ac system to the other must therefore be considered when
designing the smoothing reactor and when rating the components in the Þlters.
8.7.2 Multi-infeed schemes
For a single-infeed scheme in a low or very low SCR system, the highest TOVs are most often caused by a
disturbance in the dc system. These can include the convertor ac buses, as well as dc line faults and ac faults
in the rectiÞer or inverter. As soon as the convertors resume normal operation, the overvoltages are damped
to values that will not impose any stresses on the equipment. However, if multiple dc schemes are connected
electrically close to each other, the situation is more complex. Disturbances in one of the systems, such as a
load rejection, will cause high TOVs, even though the other scheme(s) is (are) running properly. This must
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be considered when designing the equipment. Particularly, the valves must be designed to commutate during
the TOVs that might occur due to disturbances in other schemes. Different control actions, such as increased
Þring angles and Þlter tripping, can be used to limit these TOVs, as discussed in 8.6.
Not only are the equipment stresses of importance when discussing TOVs in multi-infeed systems. The distortion of the commutating voltage as a consequence of a disturbance in one dc system might give rise to a
malfunction in another dc system. As an example, a commutation failure in system 1 distorts the waveform
of the voltage so badly that system 2 also suffers a commutation failure, and so on. This process can, for
unfavorable network conÞgurations, jeopardize both the performance of the different dc transmissions, and
the equipment might also be overstressed.
8.7.3 Multi-terminal schemes
Multi-terminal schemes that include dc lines or cables have basically the same TOV characteristics as pointto-point transmission and multi-infeed systems, depending on the coupling via the ac system between the
terminals. A few points might be added, more as remarks rather than as speciÞc characteristics for these systems.
The dc side system is usually more complex than for a point-to-point transmission. Also, the number of conceivable operating conÞgurations is often very large. These facts make a study of TOVs on different locations on the dc side very comprehensive. The probability that a fundamental frequency or second harmonic
resonance will occur is increased in some of these operating conÞgurations. The existence of this resonance
is of great signiÞcance for the magnitude of TOVs in the system.
It is easier to locally determine a proper action to limit the magnitude or duration of a TOV in point-to-point
schemes than it is in a multi-terminal system. For a multi-terminal system, one has to consider the impact on
the other station for a speciÞc action. Such an evaluation takes time and increases the duration of the TOVs.
This fact has to be considered when designing the equipment.
8.7.4 Low- and zero-inertia schemes
In a zero-inertia system and, very often also, low-inertia system, a SC has to be installed in order to achieve
acceptable system performance. The SC might then be installed at the inverter bus, and this system conÞguration can, for certain contingencies, give rise to very high TOVs.
The most severe case occurs if the last outgoing line from the inverter ac bus is tripped. The active power
from the dc convertor will then very rapidly accelerate the SC. Furthermore, there is a very high risk that the
SC will be self-excited because of the capacitive load of the connected ac Þlters. In unfavorable cases, the
voltage will rise to high values in just a few cycles, and might jeopardize the equipment.
This fault scenario must be analyzed in detail for the pertinent schemes, and protections that prevent selfexcitation of the SC must be installed.
9. Zero- and low-inertia systems
9.1 Introduction
A feature of an island electrical system that is not connected to other networks by ac transmission lines is
that its mechanical inertia is due solely to the local rotational plant. The effect on frequency due to the permanent loss of one generator unit will depend on the size of that unit relative to the total load and on the
amount of spinning reserve in service. In cases where there is no local generation, the system inertia has to
be provided by SCs as discussed in Clause 2.
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The network of Gotland Island can be described as a zero inertia system because it operates without any
local generation. The frequency is maintained in steady and transient states by the dc link and the SCs. For
normal system conditions the Gotland network can be considered as a high short-circuit ratio system, SCR =
4.7 (based on X²d, and OSCR = 3 based on X¢d. With the largest SC out of service, OSCR is just under 3.
Both values of SCR are referred to 160 MW, which is normally the maximum operating power, although the
installed dc equipment is rated for 260 MW.
Most of the power in the Corsican system is supplied by local diesel generator units. As Corsica is an isolated
system, it depends for its inertia entirely on local diesel sets. At a system load of 60 MW, a permanent loss of
a 20 MW diesel unit could cause a considerable frequency drop. In these circumstances, the Corsican system
can be considered as having inadequate inertia. The dc station at Lucciana, tapped from the 200/300 MW Sardinia-Italian Mainland DC Link, is rated for 50 MW. It can import or export power, but in all circumstances,
it provides a 20 MW Òspinning reserveÓ for the Corsican system. The dc power is modulated in order to control
the island frequency.
The Corsican system falls between high and low SCR systems if operated at maximum power. For nominal
system conditions, SCR = 3 for 50 MW of dc power; normally, operation is lower than 50 MW at dc power.
For exceptional system conditions corresponding to a short-circuit level of 120 MVA, OSCR = 4 because the
dc power would be limited to 30 MW.
9.2 Zero-inertia systemsÑIsland of Gotland
9.2.1 Description of the system
The electrical load on the island of Gotland is normally supplied by bipolar dc cable transmission from the
mainland of Sweden, as there is no local generation. The present island peak load is 160 MW; the rating of
each dc convertor is 130 MW, with a continuous overload capability of 30 MW per pole. Four SCs provide
the voltage and frequency on the island. Their total rating is 196 MVA, and their resulting inertia constant is
1.9 s. [H = (1.7 ´ 70 + 2.5 ´ 77 + 1.7 ´ 30 + 0.8 ´ 19)/196 = 1.92 and Hdc = 2.3]. They provide a short-circuit
capacity of about 750 MVA. The frequency on the island is controlled by modulating the power of the dc
link by means of a regulator, which provides the current order to the dc convertors. The ac voltage is controlled by automatic voltage regulators of the SCs. The reactive power is supplied mainly by shunt capacitors
on the feeders and the ac Þlters: 52 Mvar at the dc inverter (busbars). The SCs are lightly loaded, in order to
provide sufÞcient margins at disturbances.
Problems related to low short-circuit capacity have not been experienced; e.g., large TOVs or voltage instability. Therefore, problems related to low inertia are discussed below.
9.2.2 Frequency deviation
9.2.2.1 Faults on the mainland
Because of the small inertia constants of the SCs, the frequency deviations at load rejections can be relatively
large. The principal relationship between the power from the SC, the inertia constant, and the duration of the
load rejection is given by Equation (1) in Clause 2. The event that causes the largest frequency deviation is a
solid three-phase fault at the rectiÞer on the Swedish mainland. This affects both dc poles, as their ac buses
are connected for operational reasons. The power to the island becomes zero and the load is supplied by the
kinetic energy of the SCs. The duration of the power interruption is determined by the fault detection and
clearing time, which is Þve cycles, and by the charging time of the cable, which is about two cycles. Hence,
the cable charging time adds signiÞcantly to the load rejection time. The frequency deviation is also affected
by the power response of the dc link after fault clearing, as determined by the dc control and the frequency
regulator. The full power is restored over some 150 ms, which is equivalent to a total power loss for a further
75 ms. Therefore, the power is lost for a total equivalent time of some 0.215 s (0.1 + 0.04 + 0.075). From
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Equation (6) in 2.3.2.1, the drop in frequency is calculated to be 2.3 Hz. This compares to 2.2 Hz obtained by
full modelling of the system. No load shedding will be performed.
With the largest SC out of operation, the frequency deviation becomes about 4 Hz. In this case, parts of the
load will be shed to ensure that the SCs stay in operation.
9.2.2.2 Faults on the island
The inverters supply the power to a 70 kV ac network to which 10 kV distribution networks are connected
through 70/10 kV transformers. The load reactive power is supplied mainly by shunt capacitors in the distribution networks. The reactive power of the inverters is supplied mainly by the harmonic Þlters and partly by
the SCs, with ample regulating margins for disturbances. The ac-busbars of the dc-convertors of both poles
are interconnected. Therefore, events in the ac-network of the island affect both poles of the convertors.
Reduced ac voltage will reduce the load as well. In addition, the inverters will experience commutation failures for faults in the 10 kV distribution networks. The commutation failures will temporarily interrupt the
supply of power and the consumption of reactive power by the inverters and will discharge the dc cable to a
negative voltage. Because of the charging time of the cable, it takes a longer time than normal for the inverters to regain commutation. Hence, a commutation failure represents a somewhat more serious event than
what is normally the case for dc transmission by overhead line. Even so, the frequency deviations are smaller
than for faults on the mainland. No load shedding will be performed. An actual commutation failure event is
described in 9.2.3.
9.2.2.3 DC link equipment faults
Most faults of the dc link are limited to one pole. For the outage of one pole the power is increased on the
remaining pole employing a 25% overload capability, which limits the frequency deviations to values that
will normally not result in any load shedding. Bipolar faults seldom occur, as the two poles are completely
separated, to the degree of the overhead line sections being installed on separate towers. Temporary bipolar
faults are comparable in their severity to faults on the mainland. For permanent bipolar faults, a black-out on
the island cannot be avoided.
9.2.3 Commutation failure
9.2.3.1 Description of the event
A three-phase short circuit in a distribution network close to the dc station on Gotland causes a commutation
failure. An oscillogram from the fault recorder in one pole is shown in Figure 9-2. Starting from the top, it
shows the ac voltages, the ac currents of the two six-pulse groups, the dc voltage, the dc current, and the
extinction angle of the dc pole. Before the disturbance, the power was 108 MW, about 43% of the rated
power, the dc voltage was 150 kV, and the commutation margin, g, was 19° degrees. (Initially the value of g
was set to 17°, and relatively numerous commutation failures were experienced, caused by faults in the distribution network.)
After the short circuit (t = 0), the commutation voltage of the inverters decreased 10 to 20% and became
somewhat distorted. It was obviously sufÞcient to create a commutation failure in one six-pulse group 21 ms
after the short circuit. It can clearly be seen on the ac phase currents, traces 3 and 4, just prior to t = 21 ms,
that a normal commutation started and that the dc current commutated back again. Then two valves connected to the same phase conducted the dc current, thus short-circuiting the dc side of the six-pulse group.
As a consequence, a fast increase of the current was obtained, trace 7. The ac voltage became more distorted
and a commutation failure was created in the other group seven milliseconds later. Then the dc side of the
pole became short circuited. Similar events took place in the other dc pole. Hence, the three-phase short circuit in the distribution network created commutation failures in all four six-pulse groups of the dc inverter.
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9.2.3.2 System performance
The bypass of the inverter started an oscillation between the inductance of the dc reactor and the capacitance
of the dc cable, which discharged the cable to a negative voltage and forced the dc current in the inverter to
zero at t = 48 ms. The cable was then charged by the rectiÞer; the transient state was determined mainly by
the current controller and the capacitance of the cable. At t = 80 ms the dc voltage approached the Òback
EMFÓ voltage of the inverter; transmission could be resumed at 60 to 70% dc voltage. The fault was cleared
and the ac voltage was restored at t = 170 ms. The sudden increase of the voltage of the inverter forced the
current to zero, after which the dc transmission resumed and the prefault power was achieved.
The principal consequence for the system was an interruption of power transmission with a duration of about
three cycles of the power frequency, but the dc link restarted and transmitted a reduced power during the
fault. The unbalance between the load and the power from the dc link was supplied from the kinetic energy
of the SCs. It did not cause any load shedding, and the frequency was controlled to its normal value by
means of the frequency controller of the dc transmission.
9.2.3.3 Conclusions
a)
b)
c)
d)
Relatively minor disturbances of the commutation voltage of a dc inverter, even operating with an
extinction angle of 19°, which is higher than normally used, can create commutation failures in all of
the six-pulse groups of the dc station.
An interruption of power transmission of short duration is caused by commutation failures.
For cable transmission, the duration of the power interruption is increased due to its capacitance,
(compared with overhead line transmission); the cable is discharged to a negative voltage and the
charging time is increased.
The short interruption of power transmission had no serious effect on the supply of the loads of the
Gotland network.
9.3 Low-inertia systemÑIsland of Corsica
9.3.1 Short-circuit ratios
The 50-MW Lucciana convertor station is connected to the Corsican 90 kV ac system at a point where the
minimum short-circuit level speciÞed for operation at full load is 180 MVA. In this case the system load is
about 60 MW and OSCR = 3.6. Given the large amount of capacitor banks installed at the convertor bus (5 ´
10 Mvar), the minimum OESCR is 2.6. In exceptional conditions the short-circuit level can be 120 MVA, but
in that case the maximum power available from the convertors is limited at 30 MW, OSCR = 4. In this case,
the OESCR is (120-30)/30 = 3.
9.3.2 Frequency deviation
As the Corsican System is an isolated network with no ac interconnection with other systems, the frequency
is very sensitive to the loss of a local generator (their maximum size is 20 MW for a total installation of
330 MW). When in the Òspinning reserve control mode,Ó the convertor station power level is limited to
30 MW so that in the event of the loss of a generation unit, the convertors can inject up to 20 MW more into
the ac system to compensate for this loss.
Then the Òfrequency control mode,Ó which is the basic control mode of the convertor station, adjusts the
power level of the inverter to maintain the system frequency at its speciÞed value (50 Hz).
The operator of the convertor station can select in advance two steps of power (12 or 20 MW) for the Òspinning reserve control mode,Ó according to the type of generators in operation on the system.
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
Direct Current, I d
trace 7
3
Ud
I
d
7
Direct Voltage, Ud
trace 6
6
5
4
Convertor transformer
valve currents for
two 6-pulse groups
traces 16 and 1-5
2
1
16
15
14
AC terminal
voltage U L
traces 12, 13, 14
13
12
During the commissioning of the convertor station, a maximum variation of 4 Hz was recorded after the voluntary trip of a 20 MW diesel unit, thus conÞrming simulator results. As shown in Figure 9-1, the convertor
was exporting 5 MW from the island when the generator was tripped. The power direction was automatically
reversed and the dc link settled to import 15 MW, and hence to restore the balance of power.
g
t=0
170
8
Commutation
Margin, g
trace 8
Figure 9-1ÑGotland inventerÑcommutation failure and recovery
9.3.3 Commutation failures
Because of local climatic and geographic conditions, ac system faults are frequent. After a survey it was
established that 80% of the system faults affecting the future convertor bus caused voltage reductions of less
than 20% at that bus. The convertor was designed to operate at g = 40° at rated ac voltage while in current
control. This choice of g has resulted from extensive ac system fault simulations and probability calculations.
The Corsican dc convertor station is a parallel tap on the SCR dc link interconnecting the island of Sardinia
and the Italian mainland. This means that a commutation failure in Corsica will also temporarily affect
power transmission in Sardinia and Italy. A probability of one commutation failure in Corsica for a period of
Þve days was found acceptable by both Italian and French utilities. Voltage reductions by less than 20% have
proved to cause no commutation failures, regardless of the operating conditions.
9.3.4 DC controls
The convertors operate in dc current control with constant power factor (tan = 1).
The station has two loops to regulate the system frequency: The fast loop modulates the power, as for a rotating machine, with a transfer function between modulated power and frequency variation in per unit of
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Hf (s) = 1/(0.02 + 0.045s); the slow loop modulates the power order in a pure integral way with a transfer
function between modulated power and frequency modulation
Hs (s) = (ki /s)*1/fn with ki = 100 MW/s and fn = 50 Hz
Both loops have their output signals limited in amplitude.
10. Recovery of dc systems from ac and dc system faults
10.1 Introduction
10.1.1 AC system faults
AC system faults in the electrical proximity of the inverter station causing inverter ac busbar voltage reductions in any or all phases may cause commutation failures in some or all of the connected valve groups. During the period of commutation failures, usually the fault duration, the associated valve groups cannot deliver
any power into the ac network.
The energy loss to the ac system during the fault is unavoidable. After fault clearing, the dc would normally
be required to recover as quickly as possible to minimize the energy loss and prevent transient instability of
the synchronous machines in the ac system. The importance of commutation failures during system faults,
and therefore also the importance of commutation failure probability for remote faults in low and very low
SCR systems, depends on the sensitivity of the receiving ac system to the energy deÞcit during the failure
and the convertor behavior during the subsequent recovery period. If the recovery period is not smoothly
controlled, the effects on the ac system can be aggravated.
10.1.2 DC system faults
Notwithstanding the potential for large power and energy loss to the ac system, from the point of view of the
behavior and response of the actual convertors, the operation resulting from dc side faults is generally not so
complex or parametrically sensitive as for ac side faults.
DC side faults within the station result in the blocking of the affected valve groups or poles and a corresponding permanent loss of the groups or poles, and thus a permanent loss of the associated dc transmission
capacity. DC side faults will be either station ground faults, station equipment faults or insulation breakdown, dc line or cable faults, or ground electrode line faults. With the exception of a temporary dc line fault,
these dc-side faults result in a shutdown of the faulted zone, which could be a convertor group, pole, or
bipole.
Bipole shutdowns should be very rare. They can be caused by multiple contingencies or sequential events, an
overall bipole control failure, a line tower failure, or auxiliary service failure common to both poles. A permanent fault on the electrode line or the common neutral connection of the poles can also cause or require a
bipole shutdown. If the neutral fault is a ground short circuit it may not always be necessary to immediately
and automatically block the bipole, since this can be done by operator action. These ground faults may be
difÞcult to detect. However, a fault resulting in an electrode line or neutral open circuit can result in high dc
voltages on the low voltage side of the pole station equipment, if the bipole is not blocked immediately.
DC station faults, either in the valve group or pole zones, lead to group blocking and, usually, shutdown of
the pole. Restoration of the pole is normally done by operator action following fault investigation and correction. Alternatively, if the fault is a permanent fault in a valve group zone, in some schemes the group can
be isolated and bypassed by switches or breakers, and the remaining healthy groups in the pole can be
restored to full power. In this case, it is possible to employ an automatic sequence that detects the fault zone,
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blocks, bypasses, and isolates the faulty group and automatically restores power in the remaining healthy
groups in the pole. For most dc applications in low and very low SCR ac systems, however, these sequence
times are likely to be long enough, and the energy loss large enough, that they are not likely to meet the
required constraints for transient stability. As a result, most present schemes employ only manual pole restoration.
It follows from the above that, in the context of dc recovery within a low and very low SCR ac system, only
temporary dc line faults are relevant, and therefore only these will be discussed further in this clause as a category of dc side faults.
10.2 Parametric behavior of the phenomena
10.2.1 Effect of commutation margin angle g
Where inverters are operated at g of 18° (on 60 Hz) it is likely that an ac voltage reduction to less than about
85Ð90% at the inverter may frequently cause commutation failures. However, with g about 20° or larger, it is
not likely that commutation failures would occur for such or even greater voltage reduction. The effect of
various gs is also discussed further in 10.4, using actual system examples.
In dealing with the fundamental principle of the margin angle, special mention should be made of the effect
of single phase-to-ground faults in the ac network. The commutation voltages on the convertor valves correspond to the phase-to-phase voltages on the ac side of the system. It can easily be demonstrated vectorially
that a single phase fault results not only in a voltage drop in the phase-to-phase voltages but also in a phase
shift, and where the relative shift of one voltage is leading and the other lagging. The phase shift in the leading direction effectively infringes on the commutation margin angle and, combined with the voltage drop,
increases the probability of commutation failure.
If single-phase tripping and reclosing are applied in the vicinity of the inverter station, special actions must
usually be taken. If the system is weak and the single-phase tripping and reclosing occur on a line that has
large signiÞcance for the operation, the dc power has to be reduced during the time between tripping and
reclosing to avoid disturbances in the ac system. Such a scheme has been implemented for the Highgate convertor station [B12].
For remote faults the voltage drop and phase shift may be small, but the phase shift can reach a value of 30°
for a fault close to the busbar of the convertor station. These phase shifts can only be recognized by the dc
controls if Þring synchronizing voltages are developed out of the ac phase-to-phase voltages. An appropriate
strategy could then theoretically reduce the probability of commutation failures.
g controllers often utilize the minimum g history occurring over the last power frequency cycle (out of 12
commutations for a 12-pulse group) to possibly avoid successive commutation failures with a distorted
waveform.
10.2.2 Effect of ac system strength on commutation failures
Generally, it can be expected that the weaker the ac system at the inverter, the more likely an ac fault remote
from the inverter will cause commutation failures, since it is more likely to result in a larger voltage reduction (or be manifested as a voltage phase shift for single phase faults) at the inverter.
An apparent anomaly can arise in some situations where the system strength is seemingly increased but the
inverterÕs exposure to system faults and hence incidence of commutation failures is also increased. This does
not imply that the inverterÕs performance is worse with the stronger system. One has to be careful in evaluating the relative causes and effects. An extreme example of this would be if an entirely separate system was
connected to an inverter or it was already connected to an ac system by a new tie line. This new system
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would effectively increase the total system strength and actually improve the inverter performance for
remote faults in the previously connected system. However, the inverter is now exposed to all the faults in
the new system, and this has to be considered as well. A less obvious example could be a new line added to
an existing system. The new line may increase the equivalent system strength and generally improve inverter
performance, but it may also increase the inverterÕs effective exposure to faults in a network at the end of that
line or, of course, on the line itself.
Another scenario could be postulated where a new system addition may increase the system strength but
move the system, as seen at the inverter, closer to a harmonic resonance. Under certain faults or switching
actions, this could inadvertently increase voltage distortions, increase incidence of commutation failures,
and deteriorate the inverter performance.
10.2.3 Quality of recovery from commutation failures
Recovery after faults is usually easier with a high SCR system and takes longer with a low and very low
SCR system. Normally, however, it is the weak inverter ac system that is more in need of fast recovery to
preserve stability. On the other hand, post-fault system swings and voltage instability at the inverter bus of
certain weak systems may cause subsequent commutation failures. In these cases, slower rates of dc recovery may be desirable and must be optimized.
Very low SCR ac systems may have difÞculty providing sufÞcient reactive power at the rate required for fast
dc system recovery. Also, such systems may exhibit high TOVs with severe ac voltage distortion due to harmonic current injection caused by magnetizing inrush currents at re-energization of the convertor transformers upon fault clearing. DC convertor controls have difÞculty in operating correctly against such highly
distorted ac voltages. This can result in commutation failures and delayed recovery of the dc system.
Commutation failures from unbalanced ac system faults can excite dc side low-order harmonic resonances
that may then interact with harmonic resonances on the ac side leading to failure to recover, or at best,
delayed recovery.
For low and very low SCR ac systems with high mechanical inertia where fast injection of real power to
maintain frequency is not necessary and fast dc power response could result in unsuccessful recovery, it may
be prudent to extend (or delay) the dc recovery time. Control strategies to accomplish this are discussed in
10.2.4.
The strength of the ac system is of course relative to the dc power or power rating of the connected dc convertors. For a particular ac system, recovery from faults becomes more critical and difÞcult with increasing
dc power injection. This is just another way of expressing that it is the SCR that is relevant. It is especially
important to note here the special case of multi-infeed dc; that is, the case in which more than one dc link or
group of convertors are connected to a system. Even if they are not connected to the same point in the system
but are within electrical proximity, it is the total dc power of all convertors that is relevant to the recovery
phenomena. It may be particularly onerous if all convertors are required to recover at the same rate and in the
same fashion. In some cases of low and very low SCR systems, therefore, it may be advantageous to have a
staggered recovery of convertors for multi-infeed situations. This has the same effect as artiÞcially increasing the SCR for this situation.
In general, the time for a dc system to recover to 90% of its pre-fault power following ac fault clearing is typically in the range of 100Ð300 ms. In some cases where delayed or ramped recovery is adopted, which may
be necessary with low and very low SCR ac systems, the recovery time may be longerÑsay, 500 ms. The
recovery time depends on the characteristics of the dc and ac systems and the control strategy used.
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10.2.4 Effect of ac and dc system characteristics and dc controls on recovery from ac faults
The important characteristics of the dc system that inßuence the recovery time include dc line inductance, dc
line capacitance (particularly if it is a cable system), dc line reactor inductance, resonances of the dc main
circuit at harmonic frequencies, convertor transformer reactance, saturation characteristics and magnetizing
inrush current characteristics, types of ac harmonic Þlters provided (particularly their damping effect at low
harmonic frequencies), and type of reactive power compensation provided. The important ac system characteristics include its equivalent impedance at the fundamental frequency, its impedance at low-order harmonics (second to fourth), the damping effect of nearby loads, system mechanical inertia, ac fault clearing times,
and the method of control of voltage at the interface bus.
The ac system impedance is of importance in two frequency regions. One is at the two sideband frequencies
of fo ± fm , where fo is the system frequency and fm is the modulation frequency in the range of 10Ð30 Hz.
This frequency region is relevant to convertor stability and machine shaft resonances and, in transient form,
covers the main part of convertor recovery after faults. Usually, the ac system impedance (or the SCR) is sufÞciently deÞned at the mean of the sideband frequencies; that is, at fo .
The second important region is at the harmonic frequencies from about the second to fourth harmonics. This
fact is relevant because, with a low and very low SCR ac system, the resonant frequency of the ac system
impedance with capacitor and Þlter banks will be in this region. These low-order current harmonics are
excited by both the shock of restoring ac voltage and by magnetizing inrush current after a fault, and cause
ac voltage distortion. Above about the fourth or Þfth harmonic, ac system impedance is of little importance
for convertor stability and recovery, because ac Þlters act as a barrier to such frequencies. For simulator studies this gives the useful result that the representation of ac lines can be by relatively long lumped sections. It
should be noted that harmonic impedances are of less importance where damping exists due to nearby loads,
or where damping is provided by low-order damped ac Þlters.
Satisfactory recovery of a dc system from ac system faults is possible only when the desired operating point
in the steady-state is stable. Stable operation here refers to the dc system response to small or medium perturbations of the ac system reference conditions, such as the commutation voltage. For small perturbations
(e.g., oscillations with frequencies of the order of 3Ð10 Hz), the dc system response is determined by the
parameters of the main circuit (such as was mentioned earlier), the convertor control system (i.e., type, gain,
phase advance settings, etc.), possible static compensator controls, and possibly the master controls and telecommunications. Below 3 Hz, stability depends also on damping controls, and on ac system machines and
their controls.
For medium perturbations, such as slow changes of ac voltages within ± 10%, the dc system response is governed by the convertor current-voltage characteristics and can manifest itself as Òcrossover instabilityÓ with
weak ac systems. A possible remedy in such cases is to modify the voltage-current characteristics of the convertor in the so-called Òcurrent margin error regionÓ to obtain stable operating points in the whole range (see
4.4).
Most present-day dc control systems are capable of resynchronizing and commencing correct operation of
the dc system within two cycles of clearing a severe ac fault, such as a three-phase to ground fault. Also the
gains and time constraints of the control systems are such that they do not limit or increase the recovery time
set by the main system characteristics, and there is no signiÞcant delay in changeover between different control modes at the same convertor; for instance from constant g to constant-current.
With modern thyristor valves there need not be any delay in the recovery due to waiting for recharging of the
valve-Þring supply following ac fault clearing for fault durations (up to a speciÞed maximum). Control strategies, designed to obtain the desired optimum response of an integrated ac/dc system, may not always
require fast recovery of the dc system from ac faults.
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To obtain good dc system recovery (that is, no postclearing commutation failures), control strategy alternatives can include delay or slow ramp recovery, reduced current level, and reduced power level at recovery
(especially when part of the receiving or sending end system is disconnected due to some fault). Another
method that has been found to be helpful in improving recovery is to switch the dc system control mode
(master control level) from constant power control to constant current control. There are several ways of
doing thisÑsome explicit, some implicit:
a)
b)
c)
d)
Action taken by the master control to revert to current control on detection of ac voltage depression
(explicit).
Placing an upper limit on the current order (at a reduced level or at the prefault level) by the master
control. This explicitly states that whenever the power control function orders a current order higher
than this Þxed limit, the control mode will revert to current control.
The implicit methods involve Þltering, limiting, or clamping the dc voltage feedback signal.
Sometimes the time response of the power control function is made very long such that the purpose
of power control is to ensure that the operator requested power order is delivered on average (in the
steady state), but that for all practical purposes, during transients the control mode can be considered
to be constant current. For this purpose, the power controller function has a response time of several
seconds.
A voltage-dependent current order limit (VDCOL) function is normally provided in dc control systems
(see 4.6). This function can have an important role in determining the dc system recovery from faults, particularly from faults in a weak receiving-end ac system. The action of this function is to limit the current order
as a function of the reduction in dc line voltage. There are many variations of the implementation of this
function, including the following:
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Differing delays on imposing limits
Ramped or exponential limit application
Stepped or proportional current order reduction
Hysteresis between decreasing and increasing voltage thresholds
Different delays and ramps for release of limits
Different characteristics at different terminals.
The voltage feedback signal used is sometimes actually derived from the rectiÞer and inverter ac system
voltages, rather than from the dc line voltage. This is particularly true for back-to-back dc systems.
If the VDCOL function is activated during an inverter ac system fault, the result will be to decrease the dc
current and hence the inverter reactive power consumption, thus helping to support the ac system voltage. In
the case of severe single line to ground faults, the VDCOL may also help to recover normal commutation
and thus some power transfer can resume during the fault. Following fault clearing, the removal of the
VDCOL function current limit may be delayed and ramped so as to maximize the recovery rate while avoiding subsequent commutation failures.
One variation is to have VDCOL action at only the rectiÞer with a high minimum a at the inverter (e.g., 115°).
Approximately 40% (cos 115°) line voltage must be established by the rectiÞer before current ßows, thus minimizing reactive power consumption. Therefore, the minimum a inverter characteristic relative to the VDCOL
characteristic is important. The VDCOL here is applied and released with different time constants.
If single-phase tripping and reclosing are applied in the vicinity of the inverter station, special actions must
usually be taken. If the system has a low and very low SCR and the single-phase tripping and reclosing occur
on a line that has a large signiÞcance for system operation, the dc power has to be reduced during the time
between tripping and reclosing to avoid communication failures and other disturbances in the ac system.
Such a remedial scheme has been implemented for the Highgate convertor station. For ac lines not in the
immediate electrical vicinity of the inverter, single-phase tripping and reclosing would enable a continued dc
power transfer [B11].
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It should also be noted that following a commutation failure due to an ac fault, the inverter current may not
need to be reduced by VDCOL action even for schemes with low SCR. If the disturbance is of short duration
(100Ð200 ms), rated current may be held in the dc circuit during the fault, which could subsequently speed
up the normal restoration of prefault conditions since no ramping-up process would be necessary. Each
scheme would have to be studied in detail to determine the possible advantages of this strategy.
10.2.5 Parameters affecting recovery from dc line faults
It was previously established that for faults on the dc side, only temporary dc line faults are relevant for dc
recovery within a weak ac system.
DC line faults can be caused by ßashovers due to lightning overvoltages, insulator contamination ßash-overs,
ßashovers due to overvoltages arising from faults or control malfunctions, insulation ßashover caused by airborne pollutants, and ionization from such things as forest Þres, conductor-tree contact, and tower failures.
Most faults caused by insulation ßashovers are temporary in that they can usually be cleared by a shortduration controlled de-energization of the affected pole.
In contrast to ac system faults, where the ac voltage and system behavior are interactive with the dc behavior,
dc line faults are mainly a matter of the total energy loss for the receiving ac system. However, it is possible
to draw down the rectiÞer ac voltage during controlled de-energization if the rectiÞer system is weak. This
results from the sudden and large reactive demand during large convertor Þring angle changes. This is not
likely to be of much signiÞcance unless the voltage reduction is very severe and if special problems exist in
the rectiÞer system.
The most common causes of line faults usually result in a single-pole fault with the other healthy pole
remaining unaffected in terms of power. In some cases, where the dc is operating below full load, the healthy
pole can quickly increase its power to help compensate for the temporary interruption of power ßow on the
faulted pole.
Single-pole faults in a bipolar system can cause two side effects with respect to electrical operation on the dc
side. There will be a surge of neutral or electrode current, equal in magnitude to the healthy pole current,
until the faulted pole recovers. Also, the healthy pole can experience a transient overvoltage in the order of
1.7 pu as a result of induction from the sudden voltage collapse on the faulted pole.
In some cases, where faults are caused by insulator failures or pollution, recovery to full voltage may not be
successful and the fault may simply re-establish itself. Following an unsuccessful recovery attempt, some
schemes employ a recovery attempt at reduced voltage in order to recover as much energy as soon as possible. Reduced voltage operation requires the use of higher Þring angles, valve group blocking, or a combination of both.
The energy lost to the ac system is ultimately dependent on the total control sequence used to clear the fault.
This sequence is basically composed of the fault detection, de-energization control action (rectiÞer Þring
angle force-retard), a waiting period or deionization time, and a restart control where the voltage recovers at
some predeÞned set rate.
Faults can be detected by rate of change of voltage sensing at the line ends, by voltage level sensing, by line
end current differential, or by some combination of these. The subsequent control action normally retards
the rectiÞer Þring angle even into the inverter operating region to quickly absorb all energy from the dc line
and deionize the fault.
Since the detection and control action is relatively very fast, the most signiÞcant factors affecting the energy
loss are the deionization time, the number of restart attempts that may be required to clear a particular fault,
and the recovery rate.
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Typically, all actions including detection, force retard, and controlled restart to 90% power, but excluding the
deionization time, can require less than 50 ms. Depending on many factors including ßashover mechanism
and air conditions, the deionization time required may be of the order of from 100Ð500 ms to ensure a high
restart success rate.
10.2.6 Effect of compensation type on recovery from faults
During a fault, SCs reduce the net effective impedance by the shunting effect of their transient reactance. Their
effect on stability and recovery from faults depends on speed and optimization of their excitation system.
Static compensators act differently than SCs in that they neither increase the inertia or necessarily reduce the
effective impedance of the ac system. Their effect on the impedance depends on the compensator type and
their mode of operation at any particular time. Certain compensator types, if so designed, can react quickly
to limit undervoltages and overvoltages during and following faults and also stabilize the voltage. Static
compensators cannot directly inßuence the sensitivity of ac system frequency to ßuctuations in power
caused by a fault. However, they can be applied to reduce power ßuctuations by improving recovery times
and stability.
10.3 Different types of schemes
Discussion and consideration of recovery from faults for other transmission schemes are generally similar to
those described for normal point-to-point transmission. Fundamental differences for various types of
schemes that may have to be considered are discussed below.
10.3.1 Back-to-back schemes
The fact that a back-to-back transmission system has no dc line and that both the rectiÞer and the inverter are
located in the same building results in some differences, as compared to point-to-point transmission, in the
precondition for recovery performance.
The control equipment for the rectiÞer and the inverter are normally so close to each other that it is as easy to
interconnect them as to interconnect control subsystems in one convertor station. Thus, control actions can
be taken at the same time in both the rectiÞer and the inverter for ac and dc system faults. This can be used to
improve the recovery performance as the rectiÞer and the inverter can be easily coordinated at recovery.
A consequence of this is the better possibility, when compared to line transmission, of avoiding commutation failures in the inverter connected to a weak ac network, after ac system faults. Another consequence is
that the recovery after a fault can be more easily controlled, this being especially important when the receiving ac network has a low or very low SCR. In this case, a smooth recovery may be required to prevent the
voltage in the network from being so disturbed that subsequent commutation failures occur. For these reasons, it is likely that a back-to-back transmission system can be operated with a weaker inverter ac network
than is possible for point-to-point transmission.
The delay in recovery after an ac system fault caused by the necessary charging of the line in a point-to-point
transmission is, of course, of no consequence in a back-to-back scheme.
A back-to-back transmission link is more easily subjected to harmonic disturbance interactions between the
two connected ac networks than a dc system with a long overhead line or cable. Harmonic disturbances in
the rectiÞer ac network may, for that reason, cause distortions in the inverter if the ac network connected to
this station has a very low SCR value. A case which must be considered is the recovery after a zero impedance three-phase fault in the rectiÞer, especially if the rectiÞer ac network has a low or very low SCR. When
the ac voltage recovers, the inrush current to the convertor transformers causes distortion in the rectiÞer
commutation voltage and the corresponding harmonics are transferred to the inverter ac network via the dc
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circuit. If the ac system with ac Þlters and shunt banks, located at the rectiÞer, is in parallel resonance at, or
close to, the second harmonic, the distortion will be considerable. This phenomenon must be studied, for
instance on a dc simulator, for a speciÞc back-to-back project with weak ac networks to investigate the risk
of commutation failures.
10.3.2 Multi-terminal schemes
In a multi-terminal dc system with a moderate number of nearly equal-rated convertor stations, with none of
the connected ac networks having a very low SCR, a recovery performance similar to that for point-to-point
transmission can be obtained for ac system faults.
However, if there is a station in the dc system with a signiÞcantly lower rating than the average, and especially if its connected ac network has a very low SCR, special precautions may be needed to attain optimal
recovery performance for the whole dc system. To judge the signiÞcance of the ac network in this case, its
SCR should be related not only to its own convertor capacity but also to the total transmission capacity of the
dc system.
This situation may require some precautions for the recovery after a ground fault in any of the connected ac
networks. The small convertor, when in inverter operation with its low or very low SCR ac system, may not
be able to manage a fast recovery without the risk of an ac voltage collapse that affects the recovery of the
whole dc system. On the other hand, fast recovery may be required for the other larger stations. This contradiction may be solved by letting the small convertor recover its dc voltage as quickly as possible in conjunction with all connected convertors but delaying the increase of current through it, enabling the other
convertors to have a fast power recovery. In some cases, it may be necessary to block the small convertor to
allow other convertors to recover.
A multi-terminal dc scheme can exist in a variety of conÞgurations, especially if it includes four or more
convertors. Optimal recovery performance for each conÞguration requires various recovery control parameters and strategies.
For faults on the dc side in multi-terminal schemes, special considerations can exist for the various conÞgurations. All dc-side faults will, at least temporarily, affect all convertors connected to the faulty pole in all the
separate stations of the scheme. In some cases, a permanent fault may involve action sequences to switch
and isolate a dc line and/or a convertor. These may involve parallel or radial dc lines and parallel or series
convertors. If the isolating switches are full dc breakers, they would be capable of interrupting dc current and
withstanding the recovery voltages, and also could provide load-breaking capability. Without dc breakers,
the action sequence must ensure that the dc currents are reduced to zero and this may require signiÞcant station-to-station control coordination, signalling, and delay times. In some conÞgurations, switches may only
require a capability to commutate dc current to a parallel path that would be much less duty than full load
breaking. Example applications of this would be switches on parallel dc lines or a metallic-return transfer
breaker, where dc current is diverted from a ground return to a line conductor current return in a pole.
10.3.3 Multi-infeed dc schemes
A special case may be made for situations where more than one dc transmission scheme is feeding into the
same ac system; that is, multi-infeed dc. Mention was already made in 10.2.3 of the potential advantage of
having staggered recovery of convertors from ac system faults for this situation.
A SCR deÞned as the quotient between the network short-circuit capacity and the totally installed dc power
may be very low in this type of conÞguration. For that reason, a fast recovery of all dc transmission at the same
time after an inverter ac network fault may not be possible. Thus, either such a joint recovery must be made
slowly or other measures must be taken to avoid causing a collapse of the ac network voltage at recovery.
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For example, two separate inverters may be connected to the same ac bus, or inverters may be connected to
different buses in the system. If both inverters have, in principle, identical recovery strategies, then an ac
fault may require that the ac system must support the recovery of both inverters or the recovery of total dc
power. Alternatively, it may sometimes be possible to help a particularly weak system by delaying the recovery of one inverter until the Þrst inverter has recovered to normal. It may also have to be determined whether
a commutation failure in one inverter could cause sympathetic commutation failures in other inverters by
means of ac transferred distortions. Thus, it is important that commutation failures do not also occur in the
inverter following recovery after a fault in the rectiÞer ac network. A rectiÞer can drive current so fast that
inverter g is reduced to the commutation failure point. A weak inverter ac system can aggravate this effect
through a collapsing ac voltage inducing a faster and higher dc line current rise.
10.3.4 Low-inertia systems
The case of infeed of dc power to an isolated network with low inertia is a special case of the more general
one with infeed to a weak network.
An interruption of power transmission in this case causes a decrease in frequency, and the control system for
the inverter must be designed for operation with a low network frequency. The frequency decrease following
a temporary interruption depends on the duration of the fault, the load in the island network during the fault,
the speed of recovery of the dc link, and the inertia of any SCs that may be installed to make inverter operation possible.
From an economic point of view, it is normally desirable to choose a SC that is as small as possible. However, a small machine means both a low inertia, which gives large frequency ßuctuations at disturbances, and
a low short-circuit power, which gives associated large voltage ßuctuations. Studies need to be performed to
investigate the necessary size of the SC(s).
Since the losses in the network are of great importance for the dynamic performance of dc transmission connected to a low or very low SCR ac network, the loads in the island network should be taken into consideration. An isolated ac network with low inertia is often of small geographic extent and the loads are found
electrically close to the inverter bus. This is important for the behavior of the dc system.
10.4 System experience and examples
10.4.1 AC system faults
The following are some examples of control strategies used to obtain good dc system recoveries and some
examples of fault responses from actual systems.
For the Itaipu dc system, a 320 ms restart time was found to be better than a 160 ms restart time for a threephase fault at the inverter. The dc voltage measurement time constant was increased from 50 ms to 500 ms.
A current control mode of operation with a prefault value of current order was adopted at the inverter for ac
system faults at both Itaipu and Highgate.
Both at Miles City and at Sidney, for a Þve-cycle, three-phase fault at the inverter, the restart delay after fault
clearing is two cycles, the recovery current is 0.3 pu. For Miles City (SCR = 2.0), the recovery rate is 2 pu/s,
giving a recovery time of 450 ms. At Sidney, where the SCR is about 3.5Ð6.0, the recovery rate is 10 pu/s,
giving a recovery time of 90 ms. For loss of the Sidney-Stegall line, the east to west power ßow is limited to
125 MW, and from west to east, it is in the range of 75Ð100 MW. This type of power reduction for loss of a
critical line is implemented for Highgate also. In the Cross Channel scheme (minimum ESCR 2.5) the recovery to 80% of the power varies from 100Ð150 ms, depending on the fault.
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On the Des Cantons-Comerford DC Link between Hydro-Quebec and New England, maximum power order
limits are imposed for the loss of certain key ac lines. At Des Cantons, a power order limit is imposed to
avoid ac system voltage instability whenever the single 735 kV ac line feeding the substation is disconnected. The limit imposed is a function of both the local load level on the 230 kV network as well as the
direction of power exchange over the dc link. The power reduction limits imposed at Comerford are to avoid
serious overloads of ac transmission lines or ac voltage stability problems. The limits depend on which ac
line is lost and on the direction of power transfer. The limit is imposed instantaneously when the problem
associated with a particular outage is related to ac voltage stability. When the problem is related to thermal
overload, the power order is ramped to its limit over a period of a minute or more.
On the Nelson River system, bipole 1 maintains valve Þring during the fault and advances g in an attempt to
recover commutation. This strategy attempts to recover power as fast as possible. However, the corresponding reactive consumption tends to reduce the ac voltage further and recovery may be critical for certain weak
system situations. On bipole 2, a protection sequence is used if the commutating voltage falls below 0.5 pu.
The rectiÞer is then force-retarded by an a-ramp to a 120° limit, and the inverter is put into bypass pair operation followed by pulse blocking. When the ac voltage recovers to above 0.85 pu, the pulses are deblocked
and the current is allowed to recover. Bipole 2 recovers within about 170 ms after fault clearing. The different mechanism and rate of recovery between bipoles 1 and 2 is deemed in some cases to be beneÞcial for
total dc recovery against the weak inverter ac system (minimum ESCR = 2.5).
Figures 10-1 and 10-2 show typical commutation failures and responses of Nelson River bipoles 1 and 2,
respectively, for ac faults remote from the inverters.
+450 kV Pole Volts
-450 kV Pole Volts
+ Pole Current
- Pole Current
AC Voltages
Figure 10-1ÑNelson River bipole 1 response for ac system fault
Fi
10 1
+ Pole Volts
- Pole Volts
+ Pole Current
- Pole Current
AC Voltages
Figure 10-2ÑNelson River bipole 2 response for ac system fault
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Std 1204-1997
Figure 10-3 shows a typical commutation failure at Sellindge terminal of the 2000 MW Cross Channel DC
Link where 60 MWás was lost during the commutation failure with about another 50 MWás being lost during
the recovery. In the case of a system having a high SCR value, this would not normally be noticed, but in this
case a commutation failure occurred. It was almost certainly due to a phase shift on the 400 kV system that
triggered an acceleration-sensitive device on a large generator, which consequently unloaded. The value of g
at Sellindge is 15° on 50 Hz, and the fault level is generally in excess of 12 GVA.
Valve Currents
Value Currents
400 kV Bipole
Voltages
Pole Current
Pole Voltage
12 Pulse Volts
Measures
Figure 10-3ÑSellindge (Cross Channel) commutation failure due to lightning strike on
remote circuit
Figure 10-4 illustrates a more unusual event and gives a rather better illustration of the capabilities of a modern convertor. Following severe storms in October 1987 in southern England and northern France, there was
signiÞcant insulation pollution, which resulted in many ac system faults in both countries. One event in particular led to a persistent high impedance line fault that reduced the voltage on one phase of the CEGB
400 kV system to 0.8 pu for about 0.5 s. As Figure 10-4 illustrates, the initial voltage reduction resulted in a
commutation failure of the UK inverter, but the dc link was able to resume operation within a few cycles of
the beginning of the incident, continuing to transmit almost the ordered power throughout the 0.5 s voltage
reduction. The conditions during this event were remarkably stable in that the direct voltage, although somewhat reduced, was well smoothed by the comparatively large cable capacitance, and the inverter proved
capable of continuing to operate with no further commutation failure in the face of severely unbalanced ac
network voltages. There has been some occasional discussion on the efÞcacy of commutation failure prediction circuits. Opinion is divided on whether their advantages outweigh their disadvantages. It is interesting to
note that this performance was obtained from a convertor whose normal steady state g is 15° (on 50° Hz),
incorporating no commutation failure prediction circuits.
10.4.2 DC system faults
On the Nelson River system, line fault tests have been conducted in an attempt to determine an acceptable
minimum deionization time required to clear a temporary pole to ground fault and allow successful restarts.
These tests indicated that 100 ms should be sufÞcient, and this has been implemented. However, there has
not been long-term experience with natural line faults using this deionization time because, until recently,
automatic restarts were not allowed, due to power surge constraints imposed by the receiving-end ac system.
Figure 10-5 shows the dc response and recovery from a dc line fault. This particular restart used a 200 ms deionization time. These traces also show the fault side effects of induction into the healthy pole, and the healthy
pole voltage reduction due to rectiÞer ac voltage depression with increased reactive consumption during Þring
angle force-retard.
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Outer group
Valve Current
Inner group
Valve Current
400 kV Bipole
Voltage
Pole Current
Pole Voltage
12-Pulse Voltage
(AC Response)
Figure 10-4ÑSellindge (Cross Channel) commutation recovery following prolonged
ac lineÑground fault
Figure 10.4
Sellindge (Cross Channel) Commutation Recovery
P2 + 300kV
1
2
2
1
P I - 450kV
3
P2 I
P1 I
Bipole 1 Power
Dorsey bus voltage - 1 phase
(1)
(2)
(3)
+ ve sequence (metallic mode ) wave - opposite polarity induction in healthy pole.
- ve sequence (ground mode) wave - same polarity induction in healthy pole.
The current in Pole 2 increases to compensate for voltage reduction.
Healthy pole voltage reduction is due to rectifier and ac voltage depression, which
in turn is due to increased var consumption when forced retard is applied.
Line Travel Time = 3.2 msec
Figure 10-5ÑDC line fault on Nelson River
bipole
1 near rectiÞer with successful restart
Figure
10.5
(inverter
traces)
DC Line Fault on Nelson River BP-1 Near Rectifier
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10.5 Methods and tools for studies
Various study tools, ranging from standard load ßow and stability programs to full dc simulators, can be
used to study important aspects of dc recovery from faults.
To study the performance and optimization of the dc side, considerable modeling detail of the dc system and
controls is required as well as a three-phase representation of the ac network, effect of harmonics, unbalances and non-linearities, etc. For recovery from normal faults up to about 300 ms, however, an ac system
can be represented relatively simply as a Thevenin equivalent of Þxed EMF behind a linear impedance.
Machine controls do not have time to change appreciably in this time, and any phase change due to Þnite
inertia is irrelevant to convertors.
DC side studies therefore require the use of dc simulators or their near equivalent digital programs, such as
electromagnetic transient programs. Studies can include the sensitivity of dc recovery to such things as voltage distortions due to saturation nonlinearities, control constants and strategies, and dc current ramp rates.
At an early stage of the dc system design, the dc side studies indicated above may be used to determine the
approximate dc response and power transfer for various faults and the possible dc recovery times. This information can then be used to study the corresponding effect of faults on the ac system. An interactive optimization must then take place.
For the fully integrated ac/dc studies, the system stability performance generally depends on the dc power
recovery, which in turn depends not only on the dc current recovery rate but also on the ac voltage recovery.
In addition, the dynamic stability following faults can be positively inßuenced by proper dc modulation control to provide damping.
Proper stability studies therefore require some detailed dc system modeling to at least give equivalent
responses. The representation should include correct functional simulation of the effects of dc current and g
controllers, master power controls, modulation or damping controls, telecommunication time delays, and
special dc logic or protection sequences, including group blocking, current or voltage ramps, and VDCOL.
In general, the models must not be overdetailed in order for events to take place that are consistent with the
dc solution time step. For stability purposes, approximations are useful as long as the overall real and reactive power responses are reasonably correct.
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
Annex A
(informative)
The dc conversion process
A.1 The dc conversion process: steady-state operation
A.1.1 The basic dc convertor
The basic dc convertor is a valve group consisting of six unidirectional valves acting as switches in six-pulse
operation, as shown in Figure A.1. The ac voltage is fed to the convertor through a convertor transformer. In
modern convertors the active elements in the valves consist of thyristors, and they are timed to switch in such
a way that the voltage between the dc terminals is Þxed to the desired value. This is done by the control system, which from different input signals determines when each individual valve should be Þred to obtain the
appropriate performance. The simplest dc-system consists of two six-pulse bridges connected together by a
dc line that carries the direct current. Figure A.2 shows such a simple system and how the current ßows in
the system at a certain instant. Active power is injected into the dc line by a convertor operating as rectiÞer,
and is injected into the ac system connected to the other convertor, which is operating as inverter. Usually in
practical applications, two six-pulse bridges are connected in series to obtain twelve-pulse operation, which
will be explained in the following subclauses.
Id
Ur
Xc
Ir
Us
Ut
Xc
Is
Xc
It
+
Ud
Figure A.1ÑThe basic six-pulse convertor bridge
A.1.2 Operation of the basic six-pulse convertor
To explain the operation of a six-pulse convertor, it is assumed that a constant, smooth, direct current Id ßows
through the convertor (see Figure A.3). With the convertor transformer reactance reßected to the dc side, the
dc reactors and reactance of the dc line will smooth the current, which justiÞes this assumption. The voltage
between the dc terminals of the convertor consists of the different parts of the phase-to-phase voltages at the
dc side of the convertor transformer determined by the switching of the valves. In steady state, the Þring of the
valves is done in such a way that each valve is Þred with a Þxed delay with reference to the zero-crossing of
the voltage across that valve. This delay, denoted a, is measured in electrical degrees and is called delay angle
or Þring angle. Because of the reactance of the convertor transformers, the direct current cannot commutate
from one phase to another instantaneously and the dc current is consequently shared between the two phases
during the commutation process. A detailed analysis of this process is out of the scope of this annex; the reader
is referred to bibliography entries [B53] and [B82] in Annex B for a comprehensive treatment.
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R
Rectifier
+
Ur
I
d
Inverter
+
Udl
Udr
Ui
Pd
Ui
Ur
r
Ir
Figure A2
Basic Circuit of an HVDC Link
Figure A.2ÑBasic circuit of an HVDC link
i
Ii
A.1.3 Direct voltage of six-pulse convertor
The resulting voltage shape of a six-pulse convertor is shown in Figure A.3 for a convertor operating with
a = 15° (rectifier operation). In this figure, the phase current and the valve voltage are also shown. The phasors of the ac voltage and the fundamental component of the phase current are depicted in Figure A.2. It can
be shown that the value of the dc content of the voltage between the convertor terminals is given by the following (neglecting resistive losses in the convertor and assuming overlap angle m less than 60°; i.e., no double commutation):
3 2
3
U d = ---------- cos aU vo Ð --- X c I d ( rectifier )
p
p
(A.1)
where
Uvo
Xc
a
is the phase-to-phase rms of the ac voltage at the dc side of the convertor transformer
is the commutation reactance referred to the valve side of the convertor transformer per phase in W
is the Þring angle
The commutation reactance should include the leakage reactance of the convertor transformer and other
reactances in the commutation circuit that may inßuence the commutation process. By deÞning the quantities Udio and dx through
3 2
U dio = ---------- U vo
p
(A.2)
and
I dN
3
d x = --- X c ------------p U dio N
124
(A.3)
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IEEE
Std 1204-1997
LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
Id
Ur
Xc
Ir
Us
Ut
Xc
Is
+
V1 V3 V5
Urc XIc
X
t
Us X c
U t Xc
Id
Ir
V1 V3 V5
IV
4
s V6 V2
It
Ud+
6-Pulse Bridge
Ud
6-Pulse Bridge
V4 V6 V2
Ud
Urs Urt Ust Usr Utr Uts Urs
Ud
Urs Urt Ust Usr Utr Uts Urs
Direct Voltage
Direct Voltage
3
U = 3 2 U
cos a XI
d
d
V0
Urs Urt
3
U = 3 2 U
cos a XI
d
d
V0
Ir
Urs Urt
Phase Current
Ir
V1
V1
V4 Current
Phase
V1
t
V1
V4
t
U V1
U V1
Valve Voltage
a
a +au
Valve Voltage
Urt
Urs
Urs
Urt
t
t
a+u
u
a+u
a+u
Figure
A3
Figure
A.3ÑDirect
voltage,
phaseCurrents,
currents, and valve
a six-pulse converter
Direct
Voltage,
Phase
Valve ofVoltages
Figure
A3and voltages
bridge in rectiÞer operation
of a Six-Pulse
Converter
in Rectifier
Direct Voltage,
PhaseBridge
Currents,
and ValveOperation
Voltages
u
of a Six-Pulse Converter Bridge in Rectifier Operation
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Std 1204-1997
IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
Equation (A.1) can be written as
Id
U d = U dio cos a Ð d x -------- U dioN
I dN
(A.4)
(An index N indicates the nominal value of the quantity which usually equals the rated value.) Equations
(A.1) and (A.4) are, of course, equivalent and both notations are used in the literature. If the commutation
reactance is expressed in pu based on the convertor transformer ac quantities and with the transformer rating
equal to
p
U dioN ´ I dN ´ --3
the quantities dx and Xc (pu) are related through
1
d x = --- X c ( pu )
2
(A.5)
For small values of a, the voltage Ud is positive and the convertor feeds power into the dc system given by
Ud /Id. If a increases, Ud decreases; and for an a value approximately equal to 90°, Ud vanishes. For still
greater values, the dc voltage becomes negative, which means that power is fed into the convertor from the
dc-side inverter operation.
Instead of using the delay angle for specifying the inverter operation, the angle between the current extinction of the valve and the positive going zero crossing of the valve voltage is normally used. This angle is
called the extinction angle and is denoted by g. The voltage across the convertor bridge is given by
3
3 2
U d = ---------- U vo cos g Ð --- X c I d ( inverter )
p
p
(A.6)
or
Id
U d = U dio cos g Ð d x -------U dioN
I dN
(A.6-1)
with Ud deÞned as positive in opposite direction from Id as shown in Figure A.2 for the inventer. Figure A.4
illustrates the dc voltage and phase currents for an inverter. Additional diagrams as for the rectiÞer are also
given in this Þgure.
A.1.4 Reactive power consumption
An important observation from Figure A.2, Figure A.3, and Figure A.4 is that the phase currents lag the
phase voltages both for a rectiÞer and for an inverter. This means that a convertor always consumes reactive
power, whether it operates as a rectiÞer or as an inverter. This is a generic characteristic of a line-commutated convertor. It can be shown that the reactive power consumption of a convertor is given by
3 2
Q d = ---------- K q I d U vo
p
126
(A.7)
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IEEE
Std 1204-1997
LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
Id
V1
Ur
Xc
Ir
Us
Xc
Is
Ut
Xc
It
V3
V5
+
Ud
6-pulse bridge
V4
V6
Urs Urt Ust Usr Utr Uts
Uts
V2
Ud
Direct Voltage
t
U =d
Ir
U
V0
cos a + 3
XI d
Phase Current
V1
V4
Uv1
3 2
V4
t
u+ g
u+ g u
u+ g
g
Valve Voltage
t
Urs U rt
Figure A4
Figure A.4ÑDirect
voltage, phase
current,
and and
valveValue
voltages
of a six-pulse converDirect Voltage,
Phase
Current
Voltages
tor
bridge
in
inverter
operation
of a Six-Pulse Convertor Bridge in Inverter Operation
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
or, equivalently,
Q d = K q I d U dio
(A.7-1)
with
1 2m + sin 2a Ð sin ( 2a + 2m )
K q = --- ´ ------------------------------------------------------------------4
cos a Ð cos ( a + m )
(A.8)
and m is the overlap angle (radians) determined from
cos a Ð cos ( a Ð m ) =
Id
2 X c -------U vo
(A.9)
or
I d U dio N
cos a Ð cos ( a + m ) = 2d x ------- ------------I dN U dio
(A.9-1)
The relationship between the angles a, m, and g is
a + m + g = 180° (p radians)
(A.10)
An alternative formula for the reactive power is given by
Qd = UdId tan F = Pd tan F
(A.11)
with
2m + sin 2a Ð sin ( 2a + 2m )
tan F = ------------------------------------------------------------------cos 2a Ð cos ( 2a + 2m )
(A.12)
with m in radians; or approximately
1
cos F = --- [ cos a + cos ( a + m ) ]
2
The angle F can thus be regarded as an equivalent load angle for the convertor.
Equations (A.7) through (A.12) apply to both rectiÞer and inverter operations. However, for inverter operation, due consideration must be taken to the signs of Pd and Id . For inverter operation, Equations (A7)
through (A12) can also be used if a is replaced by g, which is the normal way of expressing reactive power
consumption for an inverter.
Figures A.5a and A.5b show the relation between Qd and Pd for some different typical values of dx , xc , and
a(g). The dc voltage is assumed to be held at the nominal value.
128
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
0.7
IEEE
Std 1204-1997
a (g)
24¡
0.6
21¡
0.5
d x = 7.5%
18¡
x c = 1.5%
15¡
0.4
Q d (p.u.)
0.3
0.2
0.1
0
0
0.5
1.0
Pd (p.u.)
Figure A.5aÑReactive power consumption of an HVDC convertor as a function of the
Figure
A5a of the delay angle (a or g)
active power for different
values
Reactive Power Consumption of an HVDC Convertor
0.6
a (g) = 18¡
Q d (p.u.)
0.5
1
x = dx
2 c
8.5%
6.5%
0.4
0.3
0.2
0.1
0.5
1.0
Pd (p.u.)
Figure A.5bÑReactive power consumption of an HVDC convertor as a function of the
Figure
A5bof the commutating reactance
active power for different
values
Reactive Power Consumption of an HVDC Convertor
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
The above exact formula can be cumbersome to use for hand calculations. For most applications, the following approximate formulae give satisfactory results:
3 2 U vo 2
Q d » P d æ ---------- --------ö Ð 1
è p Ud ø
1¤2
(A.13)
or
Qd = tan [cosÐ1(cosa Ð Kdx)]
(A.13-1)
where K = Id/IdN
U dio 2
Q d » P d æ ----------ö Ð 1
è Ud ø
1¤2
(A.13-2)
(These formulae yield a value of the reactive power that is too high, but the error is, at maximum, a few percent for typical system parameters.)
The reactive power consumption of the convertors is of signiÞcance for the discussion in Clauses 2 and 3, and
therefore the formulae above will be discussed and illustrated here. It is obvious that an increase in active
power causes increased reactive power consumption if the Þring angles are kept constant. A simple analysis
shows also that an increase in dx, xc, or Þring angle (extinction angle) also causes a larger reactive power consumption. A convertor with dx = 7.5% (xc = 15%) and a(g) = 18° consumes 0.54 pu reactive power at 1 pu
active power. If the nominal a(g) is increased to 19° the reactive power goes up to 0.56 pu. By increasing dx
to 8.5% (xc to 17%), and keeping a(g) at 18°, the reactive power rated load increases to 0.57 pu. These Þgures
apply to steady state at rated conditions. If any variable varies [e.g., Id or a(g)], the effect on the reactive power
depends on the control mode of the convertor, which is discussed in Clauses 2 and 3.
A.1.5 Harmonic generation
As seen from Figure A.3 and Figure A.4, the phase currents and dc voltages contain harmonics, and a Fourier expansion of these shows that the current on the ac side contains harmonics of order
nI = 6k ± 1, k = 1, 2, É
(A.14)
and the dc voltage contains harmonics of order
nu = 6k, k = 1, 2, É
(A.15)
The amplitudes of the harmonic currents and voltages are approximately proportional to the inverse of the
order of the harmonic.
A.1.6 Twelve-pulse operation
Normally, two six-pulse convertors are connected in series to obtain twelve-pulse operation. This is obtained
by introducing a 30° phase shift between the convertor transformers of the two six-pulse convertors; e.g., by
using one Y/Y and one Y/D connected transformer. By doing this, a smoother dc voltage is obtained and the
total phase current becomes more sinusoidal (see Figure A.6). Ideally, harmonics of order
nu = 12k, k = 1, 2, É
130
(A.16)
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
IEEE
Std 1204-1997
are present in the dc voltage, and harmonics of order
nI = 12k ± 1, k = 1, 2, É
(A.17)
are present in the phase currents. Harmonics of the orders given by Equations (A.14) and (A.15) and by
Equations (A.16) and (A.17) are called characteristic six-pulse and twelve-pulse harmonics, respectively.
Due to imperfections and unbalances in the system, harmonics of other orders occur. Also, a more detailed
modeling of the components in the dc-system would show that harmonics other than the characteristic ones
are created. The characteristic harmonics are usually dominating, but consideration must be taken to the noncharacteristic harmonics. Filters are normally installed to Þlter the principal harmonics.
Harmonic Currents on the AC Side
i1
i1 + i2
i2
i1
T/4
T/2
Y Y
Y D
3T/4
t
Phase Current
i2
t
i1 + i2
t
(%)
i 1,n
10
5
5 7
11 13
17 19
23 25 n
(%)
i 1,n + i 2,n
5
11 13
23 25 n
Figure A.6ÑPhase currents and harmonic content of phase currents of six-pulse
and twelve=pulse convertors
Figure A6
A.1.7 DC system operation
A very brief description of how a dc system, including its control system, is normally operated will be given
below. A two-terminal system consists basically of a rectiÞer, a dc line, an inverter and a control system (see
Figure A.7).
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IEEE
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
Rd
ar
I
ai
r
i
Control
System
Control
System
Inputs
Inputs
Figure A.7ÑSchematic and simpliÞed description of an HVDC system
The dc current Id is determined by the voltage difference between the rectiÞer and the dc line resistance
U dR Ð U dI
I d = ----------------------Rd
(A.18)
The voltages UdR and UdI are given by Equations (A.1) and (A.6), respectively, and can consequently be
controlled by the Þring angles of the convertors. Normally, the inverter is operated in such a way that g is at
the minimum permissible value, gmin (see A1.4), which is in the range 15°Ð18°. In real time (i.e., microseconds), a minimum extinction angle, gmin, of 15° for a 50 Hz system is equivalent to 18° for a 60 Hz system
(833 ms). By doing this, the reactive power consumption of the inverter is minimized and the cost of the
valves is minimized. The desired value of the dc current is now obtained by adjusting the Þring angle in the
rectiÞer. To minimize the losses of the dc line, the dc voltage should be as high as possible. Since g is at the
minimum value, the voltage is controlled by changing the turns ratio of the inverter convertor transformers
by the tap changers. The tap changers are also used in the rectiÞer in such a way that the Þring angle is typically around 15°, so that for small ac voltage variations the rectiÞer can maintain the required current without waiting for tap changer action.
The current order to the current controller is either obtained directly as an input; e.g., from the dispatcher, or
from a power controller. The power controller determines the current order through
P do
I do = -----------------U d meas
(A.19)
with obvious notation. Usually some Þltering is included in the measurement of Ud to avoid action due to
fast transients.
132
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
IEEE
Std 1204-1997
A.2 Commutation failures
From the ac system point of view, it is important that the behavior of the dc system during transients and disturbances in the system is such that the stability and performance of the overall system is maintained. To
avoid this, special consideration must be taken. A phenomenon that plays an important role in this context is
the commutation failure that is brießy discussed here.
To establish a forward blocking capability of a valve, the stored charges in the thyristors established during
the conduction interval must be removed. Therefore, the valve requires a certain negative voltage-time area,
before it can exhibit a forward blocking capability. This imposes no problem for a rectiÞer, but could cause
difÞculties during inverter operation. As discussed above, it is desirable to keep g as small as possible, and if
for some reason (e.g., a sudden reduction of the ac voltage in the inverter) the forward blocking capability is
not established before the zero-crossing of the valve voltage, a commutation failure will occur as explained
below.
Consider a commutation from valve V1 to valve V3 in Figure A.8. Assume that after the Þring of valve V3
some disturbance in the voltage occurs that reduces the remaining voltage-time area for valve V1 in such a
way that no forward blocking capability is obtained for valve V1. Consequently, the current through valve
V1 starts to increase while the current through valve V3 reduces to zero again. The next commutation that
will take place is from valve V2 to valve V4. If this commutation is successful, this indicates that both valves
V1 and V4 are conducting current at the same time and that the six-pulse bridge is short-circuited on the dc
side.
The dc current will now increase and the dc line will be discharged through the by-pass pair. The dc voltage
across the six-pulse group will remain zero until the current is commutated from valve V4 to V6. At this time
the dc voltage starts to increase, following commutations take place in a normal way, and normal operation
is resumed. Since the dc voltage is zero during a period of time following the commutation failure, no active
power will be transmitted during this time. This might impose a substantial disturbance on the ac system. If
the system is weak, this loss of power could cause such severe disturbances on the ac system that it results in
consequential commutation failures. It is therefore of great importance that the system is designed in such a
way that commutation failures are avoided for frequent disturbances in the ac system.
The minimum permissible commutation margin, gmin, is determined from the negative voltage-time area
required for thyristors to exhibit forward blocking capacity. When determining gmin consideration must be
given to the asymmetries in the voltage distribution of series-connected thyristors, security margins, variation in component values, etc.
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
Id
Ur
Us
Ut
Xc I
r
Xc I s
+
V1 V3 V5
Ud
6-Pulse Bridge
Xc I
t
V4 V6 V2
Ud
Urs Urt Ust Usr Utr Uts Urs Urt Ust Usr
Direct Voltage
t
1-3 2-4 3-5 4-6 5-1 6-2 1-3
V3
V1
V5
V4
UV1 u +
V6
V2
Valve Currents
V1
V4
V3
V6
V2
t
u
u+
Valve Voltage
t
Urs Urt
Figure A.8ÑDirect voltage, valve currents, and valve voltages during a commutation failure
in a convertor bridge
Figure A8
134
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
IEEE
Std 1204-1997
Annex B
(informative)
Bibliography
[B1] Adapa, R., and Reeve, J., ÒDiagnosis of the response of a dc system to symmetrical and non-symmetrical ac faults,Ó Proceedings of the IEEE MONTECH '86 Conference on HVDC Power Transmission, Montreal, pp. 35Ð38, Sept. 1986.
[B2] Ainsworth, J. D., ÒCore-saturation instability in the Kingsnorth HVDC link,Ó CIGRƒ SC 14, June 1977.
[B3] Ainsworth, J. D., ÒDevelopments in the phase-locked oscillator control system from HVDC and other
large convertors,Ó IEE Conference Publication, no. 255, pp. 98Ð103, Sept. 1985.
[B4] Ainsworth, J. D., ÒHarmonic instabilities,Ó International Conference on Harmonics in Power Systems,
Manchester, pp. 76Ð85, 1981.
[B5] Ainsworth, J. D., ÒHarmonic instability between controlled static convertors and AC networks,Ó Proceedings of the IEE, vol. 114, no. 7, pp. 949Ð957, July 1967.
[B6] Ainsworth, J. D., ÒThe phase locked oscillatorÑa new control system for controlled static rectiÞers,Ó
IEEE Transactions on Power Apparatus and Systems, vol. PAS-87, pp. 859Ð864, 1968.
[B7] Ainsworth, J. D., ÒPower Limit Instability (voltage instability) in a DC link connected to a weak AC
system.Ó CIGRƒ SC14 Colloquium, England, 1985.
[B8] Ainsworth, J. D., ÒThe recovery of HVDC convertors after faults,Ó CIGRƒ SC14 Colloquium, England,
1985.
[B9] Ainsworth, J. D., Gavrilovic, A., and Thanawala, H. L., Static and synchronous compensators for DC
transmission convertors connected to weak AC systems, 31.01, CIGRƒ 1980.
[B10] Ainsworth, J. D., and Martin, C. J. B., ÒThe inßuence of HVDC links on power systems,Ó GEC Journal of Science and Technology, vol. 44, no. 1, 1977.
[B11] Andersson, G., Proceedings of CIGRƒ Session 1986, Group 14 Discussion, Preferential Subject 1,
Question 1.7, Discussion by G. Andersson.
[B12] Arrillaga, J., Al-Khashali, H. J., and Compas-Barros, J. G., ÒGeneral formulation for dynamic studies
in power systems including static convertors,Ó Proceedings of the IEE, 124, no. 11, pp. 1047Ð1052, 1977.
[B13] Bahrman, M. P., Larsen, E. V., Piwko, R. J., and Patel, H. S., ÒExperience with DC-turbine-generator
torsional interaction at Square Butte,Ó IEEE Transactions on Power Apparatus and Systems, vol. PAS-99,
pp. 966-975, MayÐJune 1980.
[B14] Bahrman, M. P., Larsen, E. V., Piwko, R. J., Patel, H. S., Hauth, R. L., and Breuer, G. D., ÒDC-turbinegenerator torsional interactionsÑa new design consideration,Ó CIGRƒ Report 14-04, 1980.
[B15] Billon, V. C., Taisne, J. P., Arcidiacono, V., and Mazzoldi, F., ÒThe Corsican tapping: From design to
commissioning tests of the third terminal of the Sardina-Corsica-Italy HVDC link,Ó IEEE 1988 Summer
Meeting.
Copyright © 1997 IEEE. All rights reserved.
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IEEE
Std 1204-1997
IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
[B16] Billon, V. C., Taisne, J. P. Charles, P., and Gruson, J. P., ÒLiaison multiterminale SACOI: Essais de
mise en service de la station de conversion de Lucciana,Ó CIGRƒ Report 14-12, 1988.
[B17] Bornard, P., Souque, D., and Vielpeau, D., ÒTorsional interactions between the gravelines units and the
2000 MW Cross-Channel dc link: Protection of the turbine-generator units,Ó CIGRƒ paper, 1988.
[B18] Bowler, C. E. J., Demcko, J. A., Mankoff, L., Kotheimer, W. C., and Cordray, D., ÒThe Navajo SMF
type subsynchronous resonance relay,Ó IEEE Transactions on Power Apparatus and Systems, vol. PAS-97,
pp. 1489Ð1495, Sept./Oct. 1978.
[B19] Brewer, G.L., and Rowe, B.A., ÒAC/DC interactions on the 2000 MW UKÐFrance (Cross Channel)
HVDC link,Ó CIGRƒ Symposium, Boston, 28Ð30 Sept. 1987.
[B20] Chapman, D. G., ÒModel veriÞcation,Ó Panel Session on HVDC Modelling For Power System Stability,Ó IEEE 1987 Winter Meeting, New Orleans.
[B21] CIGRƒ WG 33.05, ÒApplication guide for insulation coordination and arrester protection of dc convertor stations,Ó Electra No. 96.
[B22] Compendium on HVDC Schemes Throughout the World, CIGRƒ Technical Brochure No. 3, Edited by
SC 14 WG 04, 1987.
[B23] Cresap, R. L., and Mittelstadt, W. A., ÒSmall-signal modulation of the PaciÞc HVDC Intertie,Ó IEEE
Transaction on Power Apparatus and Systems, vol. PAS-95, no. 2, Mar./ Apr. 1976.
[B24] Cresap, R. L., Mittlestadt, W. A., Scott, D. N., and Taylor, C. W., ÒDamping of the PaciÞc AC Intertie
oscillations via modulation of the parallel PaciÞc HVDC Intertie,Ó CIGRƒ Report 14-05, Paris, 1978.
[B25] Ekstrom, A., ÒTransferred harmonics,Ó CIGRƒ SC 14, 1986.
[B26] Electrical Transmission and Distribution Reference Book, Westinghouse Electric Corporation, Chapter 22, 1964.
[B27] Ellert, F. J., Grund, C. E., Homer, D. L., Patel, H. S., and Schener, S. D., ÒStabilization of dc systems
by modulating HVDC system power ßow,Ó presented at the All-India Symposium of HVDC, Bombay 1978.
[B28] EPRI EL-2708, ÒHVDC system control for damping of subsynchronous oscillations,Ó Project 1425-1,
Final Report, Oct. 1982.
[B29] Erche, M., et al., ÒReactive power control in ac/dc systems by dc convertor station.Ó CIGRƒ SC 14/38
Symposium, Boston, Sept. 28Ð30, 1987.
[B30] Fehrle, K. G., and Lasseter, R. H., ÒSimulation of control systems and applications to HVDC convertors,Ó IEEE Tutorial Course, IEEE Publication No. 81, EHO 173-5-PWR.
[B31] Fick H., ÒExcitation of subsynchronous torsional oscillations in turbine generator sets by a current
source inverter,Ó Siemens Power Eng., 4, pp. 83Ð86, 1982.
[B32] Figueiredo, A. G., Praca, A. A. S., and Shore, N. L., ÒMaster control of the Itaipu HVDC transmission
system,Ó Paper presented at the International Symposium on HVDC Technology: ÒSharing the Brazilian
Experience,Ó Rio de Janeiro, Brazil, 20Ð25 Mar., 1983.
[B33] Fink, J. L., Pohl, R. V., Ryder, F. H., and Stairs, C. M., ÒSystem design considerations of the Eel River
HVDC convertor stations,Ó CIGRƒ Report 14-05, Paris, 1982.
136
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
IEEE
Std 1204-1997
[B34] Forest, R., Heyner, G., Kanngiesser, K. W., and Waldmann, H., ÒSome aspects of controlling multiterminal HVDC transmission systems,Ó CIGRƒ SC 10, Apr. 1967.
[B35] Franken, B., and Anderson, G., ÒAnalysis of dc convertors connected to weak ac systems,Ó IEEE
Transactions of Power Systems, vol. PAS-5, no. 1, 1990.
[B36] Gavrilovic, A., ÒInteraction between ac and dc systems,Ó CIGRƒ Report 14.09, 1986.
[B37] Gavrilovic, A., et al., ÒInteraction between dc and ac systems,Ó CIGRƒ SC 14/38 Symposium, Boston,
Sept. 28Ð30, 1987.
[B38] Gavrilovic, A., et al., ÒSome aspects of AC/DC system interaction.Ó Proceedings of the IEEE MONTECH '86 Conference on HVDC Power Transmission, Montreal, Sept. 1986.
[B39] Gels, H. B., Kanngiesser, K. W., Ring, H., and Wess, T., ÒTransient behavior of a series-connected
HVDC tapping substation,Ó CIGRƒ Study Committee Meeting, Vienna/Austria, 1983.
[B40] Goosen, P. V., and Becker, W., ÒReport on the equipment of the Cabora Bassa schemeÑcontrol and
protection system,Ó CIGRƒ SC14 Meeting, Johannesburg, Oct. 1975.
[B41] Grund, C. E., ÒDynamic performance characteristics of North American HVDC systems for transient
and dynamic stability evaluation,Ó IEEE Committee Report, IEEE Transaction on Power Apparatus and
Systems, vol. PAS-100, no. 7, July 1981.
[B42] Guidelines for the Application of Metal Oxide Arresters Without Gaps for HVDC Converter Stations,
CIGRƒ Technical Brochure No. 34, Edited by SC 33/14 WG 05, 1987.
[B43] Hammad, A., ÒA new approach for the analysis and solutions of ac voltage stability problems at dc terminals,Ó Proceedings of the IEEE MONTECH '84 Conference on HVDC Power Transmission, Montreal,
Sept. 1984.
[B44] Hammad, A., Szechtman, M., ÒAC voltage stability at dc terminals connected to weak ac systems,Ó
CIGRƒ SC 14 Colloquium, England, 1985.
[B45] Haywood, R. W., and Chand, J., ÒResponse of the Nelson River HVDC system to disturbances on the
receiving end ac network,Ó CIGRƒ Report 14-04, 1984.
[B46] Hedin, R., and Stump, K., ÒEffect of series capacitors on dc control system torsional interaction,Ó Proceedings of International Conference on DC Power Transmission, pp. 98Ð104, Montreal, Canada, June
1984.
[B47] Hegi, J., Bahrman, M., Scott, G., and Liss, G., ÒControl at the Quebec-New England multi-terminal
HVDC system,Ó CIGRƒ Report 14-04, Paris, 1988.
[B48] Hingorani, N. G., Nilsson, S., Bahrman, M. P., Reeve, J., Larsen, E. V., and Piwko, R. J., ÒAnalysis of
subsynchronous frequency interactions involving dc transmission systems,Ó IEEE Publication No. 80 CH
1624-6, presented at the International Conference on Overvoltages and Compensation on Integrated ACÐ
DC Systems, Winnipeg, Manitoba, July 1980.
[B49] Hingorani, N. G., Nilsson, S., Bahrman, M. P., Reeve, J., Larsen, E. V., and Piwko, R. J., ÒSubsynchronous frequency stability studies of energy systems which include dc transmission,Ó U.S. Department of
Energy Symposium on Incorporating DC Power Transmission Into System Planning, Phoenix, Arizona, Mar.
1980.
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IEEE
Std 1204-1997
IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
[B50] Jotten, R., Bowles, J. P., Liss, G., Martin, C. J. B., and Rumpf, E. ÒControl in HVDC systems, Part I,Ó
CIGRƒ SC 14-10, 1978.
[B51] Kaufhold, W., et al., ÒControl of temporary overvoltages in ac/dc systems by metal-oxide limiter,Ó
Paper 200-12, CIGRƒ Symposium, Boston, 28Ð30 Sept. 1987.
[B52] Kimbark, E. W., Direct Current Transmission, New York: John Wiley & Sons, 1971.
[B53] Kitchin, R. H., ÒNew method for digital computer evaluation of convertor harmonics in power systems using state variable analysis,Ó Proceedings of the IEE, Pt. C, 128(4), pp. 196Ð207, 1981.
[B54] Knaak, H. J., and Venne, A., ÒImproving the stability of HVDC transmission to weak networks,Ó
Paper presented to the Canadian Electrical Association (CEA) Meeting in Vancouver, 23Ð26 Mar. 1987.
[B55] Koschik, V., et al. ÒInßuence of various factors on recovery performance of a dc system feeding into a
weak ac system,Ó Proceedings of the IEEE MONTECH '86 Conference on HVDC Power Transmission,
Montreal, Sept. 1986
[B56] Lambrecht, D., and Kulig, T., ÒTorsional performance of turbine generator shafts especially under resonance conditions,Ó IEEE Transactions on Power Apparatus and Systems, PAS-101, pp. 3689Ð3697, 1982.
[B57] Lamm, U., Uhlmann, E., and Danfors, P., ÒSome aspects of tapping of HVDC transmission,Ó Direct
Current, vol. 8, no. 5, 1963.
[B58] Larsen, E. V., Baker, D. H., and McIver, J. C., ÒLow order harmonic interaction on ac/dc schemes,Ó
IEEE Transactions on Power Delivery, vol. 4, no. 1, pp. 493Ð501, Jan. 1989.
[B59] Le D, A. ÒThe French experience in the multiterminal dc links,Ó Report 87 JC-48, IEEE/CSEE joint
conference on high voltage transmission systems in China, Beijing, 17Ð22 Oct.1987.
[B60] Liss, G., and Smedsfelt, S., ÒHVDC links for connection to isolated ac networks,Ó Paper presented to
the U.N. Economic Commission for Europe, Seminar on High Voltage Direct Current (HVDC) Techniques,
Stockholm, Sweden, 6Ð9 May 1985.
[B61] Mortensen, K., Larsen, E. V., and Piwko, R. J., ÒField tests and analysis of torsional interactions
between the coal creek turbine-generators and the CU DC system,Ó IEEE Transactions on Power Apparatus
and Systems, vol. PAS-100, pp. 336Ð344, Jan. 1981.
[B62] Nyati, S., et al., ÒComparison of voltage control devices at dc convertor stations connected to weak ac
systems.Ó IEEE 1987 Winter Meeting, New Orleans, Paper 87 WM, pp. 159Ð7.
[B63] Persson, E., ÒCalculation of transfer functions on grid- controlled convertor systems,Ó Proceedings of
the IEE, 117(5), pp. 989Ð997, 1970.
[B64] Pilotto, L. A. S., Szechtman, M., and Selado, E., ÒThe problem of voltage collapse in ac/dc systems,Ó
Symposium of Specialists in Electric Operational Planning, Brazil 1987.
[B65] Piwko, R. J., and Larsen, E. V., ÒDC system control for damping of subsynchronous oscillations,Ó
EPRI Report EL-2708, Oct. 1982.
[B66] Piwko, R. J., and Larsen, E. V., ÒDC system control for damping of subsynchronous oscillations,Ó
IEEE Transactions on Power Apparatus and Systems, vol. PAS-101, pp. 2203Ð2211, July 1982.
138
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LOW SHORT-CIRCUIT CAPACITIESÑPART I: AC/DC INTERACTION PHENOMENA
IEEE
Std 1204-1997
[B67] Piwko, R. J., Nozari, F., Hauth, R. L., and Flarity, C. W., ÒControl Systems for Application in HVDC
Terminals at AC System Locations Having Low Short Circuit Capacities,Ó Proceedings of the IEEE MONTECH '86 Conference on HVDC Power Transmission, Montreal, 29 Sept.Ð1 Oct. 1986.
[B68] Porangaba, H. D., et al., ÒItaipu HVDC Transmission SystemÑStability Studies for a Weak AC
Receiving System,Ó Proceedings of the IEEE MONTECH '86 Conference on HVDC Power Transmission,
Montreal, 29 SeptÐ1 Oct. 1986.
[B69] Povh, D., and Schultz, W., ÒAnalysis of overvoltages by transformer magnetizing inrush current,Ó
Paper F 77 717-2, IEEE 1977 Summer Meeting, Mexico City.
[B70] Presson, E., ÒCalculations of transfer functions in grid controlled convertor systems,Ó Proceedings of
the IEEE, vol. 117, no. 5, May 1970.
[B71] ÒProposed terms and deÞnitions for power systems stability,Ó IEEE Transactions on Power Apparatus
Systems, vol. PAS-101, no. 7, pp. 1894Ð1898, July 1982.
[B72] Reichert, K., Terens, L., Durr, J., and Pfyl, W., ÒHarmonic interaction between static VAR system and
the network: problems analysis and solutions,Ó International Symposium on controlled reactive compensation, Varennes, Canada, pp. 142Ð173, 19Ð21 Sept. 1979.
[B73] Rowe, B. A., and Brewer, G. L., ÒResponse of the 2000 MW Cross Channel HVDC Link to Major
Disturbances,Ó CIGRƒ Report 14-08, Paris, 1988.
[B74] Stemmler, H., ÒHVDC back to back interties on weak ac system, second harmonic problems, analysis
and solutions.Ó Paper 300-08, CIGRƒ Conference on AC/DC Transmission Interactions and Comparisons,
Boston, 28Ð30 Sept. 1987.
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[B76] Szechtman, M., Ping, W. W., Salgado, E., and Bowles, J. P., ÒUnconventional HVDC control technique for stabilization of a weak power system,Ó IEEE Transactions on Power Apparatus and Systems,
vol. PAS-103, no. 8, Aug. 1984.
[B77] Taisne, J. P., ÒSardinia-Corsica-Italy system tapping,Ó Paper presented at the panel session on Practical
Aspects of Multiterminal DC Systems, IEEE PES Winter Meeting, 1988.
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(CIGRƒ Working Group 14.07, AC/DC System Interactions, and IEEE Working Group 15.05.05, Interaction
with Low SCR AC Systems).
[B79] Thio, C. V., ÒNelson River HVDC bipoleÑTwo Part IÑSystem aspects,Ó IEEE Transactions on
Power Aparatus and Systems, vol. PAS-98, no. 1, pp. 165Ð173, Jan./Feb. 1979.
[B80] Thio, C. V., et al., ÒHVDC and weak ac systemsÑutility view,Ó CIGRƒ SC14 Colloquium, England,
1985.
[B81] Uhlmann, E., ÒConvertors connected to networks with limited short circuit capacityÓ (in German),
Archive fur Electrotechnik, 1981.
[B82] Uhlmann, E., Power Transmission by Direct Current, Berlin, Heidelberg, New York: Springer-Verlag,
1975.
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IEEE
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
[B83] The Visual Perception and Tolerance of Flicker, Utilities Coordinated Research, Inc., New York, 1937.
[B84] Woodford, D. A., Gole, A. M., and Menzies, R. W., ÒDigital simulation of DC links and AC
machines,Ó IEEE Transactions on Power Apparatus and Systems, vol. PAS-102, no. 6, pp. 1616Ð1623, June
1983.
[B85] Yacamini, R., ÒHow dc schemes can excite torsional oscillations in turbo-alternator shafts,Ó Proceedings of the IEE, Pt. C, 133(6), pp. 301Ð307, Sept. 1986.
[B86] Yacamini, R., ÒHow HVDC schemes can excite torsional oscillations in turbo-alternator shafts,Ó Proceedings of the IEE, Pt. C, 133(6), pp. 301Ð307, Sept. 1986.
[B87] Yacamini, R., and De Oliveria, J. C., ÒComprehensive calculation of convertor harmonics with system
impedance and control representation,Ó Proceedings of the IEE, 133(2), pp. 95Ð102, 1986.
[B88] Yacamini, R., and De Oliveria, J. C., ÒInstability in HVDC schemes at low-order integer harmonics,Ó
Proceedings of the IEE, Pt. C, 127(3), 1980, pp. 179Ð180.
[B89] Yacamini, R., and Resendet, J. W., ÒThyristor controlled reactors as harmonic sources in HVDC convertor stations and ac systems,Ó Proceedings of the IEE, Pt. B, 133(4), pp. 263Ð169, July 1986.
140
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IEEE Guide for Planning DC Links Terminating at
AC Locations Having Low Short-Circuit Capacities
Part II: Planning Guidelines
1. Overview
1.1 Scope
Part I of the guide discusses the effects of various aspects of the ac/dc interactions on the design and performance of dc schemes where the ac system appears as a high impedance at the ac/dc interface bus; i.e., low
and very low short-circuit (short-circuit ratio ([SCR]) conditions. AC systems having zero or inadequate
mechanical rotational inertia, such as island schemes with no or with limited local generation, are also considered. Environmental, siting, and construction issues are not addressed. General issues, such as steadystate reactive compensation and ac and dc Þlter requirements, are not in the scope of this guide, but would be
included in a complete study for a particular dc scheme design. In order to assist those not familiar with dc
transmission and convertors, a brief description of basic rectiÞer and inverter operation is given in Annex A
of Part I.
Part II of this guide, which is bound together with Part I, considers how the ac/dc interaction phenomena
described in Part I should be taken into account in the planning and the preliminary design of ac/dc systems
having low or very low SCR values.
1.2 Purpose
The purpose of Part II of this guide is to apply the factors addressed in Part I (those aspects to be considered
in the design of a dc transmission scheme in the context of system interaction resulting from the dc link terminating at an ac location having one or both of low short-circuit capacities relative to dc power infeed or ac
system inertia low enough to be a concern for satisfactory dc system operation). SpeciÞcally, Part II considers the special precautions and studies in the planning stage of a dc system and provides examples from
existing schemes operating with what has been deÞned in Part I as low and very low SCRs.
1.3 General
Beyond the basic consideration of power transfer, the planning and design of a dc project takes into account
several ways in which the dc and associated ac system interact at the converter stations. As the strength of
the ac system reduces (characterized, for example, by the ac short-circuit level relative to the dc power), certain interactions tend to become more pronounced and consequently demand more attention. It is in this context that Part II is concerned with identifying the interactions and provides guidance on their successful
accommodation.
It will be evident that there are many facets of ac/dc interaction and several that are emphasized by low and
very low SCRs. For each facet, the dividing line between high SCRs and what can be considered as low is
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
not clear cut, and the extent of concern is application-dependent. Also, some dc systems, which normally
operate with a high SCR, operate with a low or very low SCR during contingency conditions. It is perhaps of
some reassurance to note that the particularly low SCRs appertaining to some schemes, which have been put
into service in the last few years, have not prevented successful operation. Furthermore, as will become evident in Clause 8, dc has been successful in some cases where the low SCR has precluded an ac link. It is
hoped that this guide will assist in the successful realization of schemes that at Þrst glance may appear to
have severe short-circuit limitations.
There is common ground in planning and design studies of dc systems irrespective of the strength of the ac
systems. It is inevitable that the users of Part II will rely on their own judgment in interpreting and weighing
the relative importance of the various issues for the application at hand.
2. References
This standard shall be used in conjunction with the following publications. When the following standards are
superseded by an approved revision, the revision shall apply:
IEC 60919-1 (1988-12), Performance of high-voltage d.c. (HVDC) systemsÑPart 1: Steady-state conditions.1
IEC 60919-2 (1990-10), Performance of high-voltage d.c. (HVDC) systemsÑPart 2: Faults and switching.
(Equivalent to IEEE P1030.2/D4, Dec. 1990.2)
IEC 60919-3... 3, Performance of high-voltage d.c. (HVDC) systemsÑPart 3: Dynamic conditions.
3. Performance criteria and evaluation
3.1 General considerations
Acceptable operation of a dc system, in broad terms, may be deÞned as smooth operation, without causing
operational problems for the associated ac power system(s) and without resulting in a signiÞcant inconvenience for power system operators. DeÞning acceptable performance criteria is, therefore, an important Þrst
step in planning a dc system.
Inasmuch as the performance of a dc system greatly depends on inherent characteristics of both the dc and
associated ac systems, it is necessary to conduct appropriate planning studies to determine the dc system
performance criteria considering ßexibility and limitations of dc systems, as well as the requirements of the
ac systems in which they are embedded.
In evaluations of performance of low and very low SCR dc applications, it may be necessary to focus on cost
versus performance criteria more than for high SCR applications (e.g. higher overvoltages and longer recovery times). In the Þnal analysis, the selection of acceptable levels of performance involves a cost versus beneÞt assessment to ensure the correct balance between over- and under-building of the system.
1IEC
publications are available from IEC Sales Department, Case Postale 131, 3, rue de VarembŽ, CH-1211, Gen•ve 20, Switzerland/
Suisse. IEC publications are also available in the United States from the Sales Department, American National Standards Institute, 11
West 42nd Street, 13th Floor, New York, NY 10036, USA.
2Numbers preceded by P are IEEE authorized standards projects that were not approved by the IEEE Standards Board at the time this
publication went to press. For information about obtaining drafts, contact the IEEE.
3This IEC standard was not published at the time this IEEE standard went to press. Publication is expected in spring of 1998. For information about obtaining a draft, contact the IEC.
142
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LOW SHORT-CIRCUIT CAPACITIESÑPART II: PLANNING GUIDELINES
IEEE
Std 1204-1997
This clause is primarily concerned with performance criteria for low and very low SCR situations. There is
concern about the effect on the ac system during normal operation (e.g., reactive supply, voltage control,
voltage change during reactive switching) and as a result of contingencies (e.g., commutation failure, ac
faults, temporary and permanent dc faults). There can also be effects that are applicable to dc applications in
general. Details of the phenomena upon which the performance criteria are based are provided in Part I of
this guide. Examples of speciÞc systems with low or very low SCRs will be presented in Part II, Clause 8.
In the evaluation of each performance criterion, it is prudent to impose requirements judiciously in order to
minimize problems, such as complaints from the general public or operating restrictions, while at the same
time avoiding over-design and consequent unnecessary expense.
Following the resolution of the performance criteria to be utilized for an application, it is then necessary to
undertake studies to ensure that decisions during the design process are consistent with meeting the performance criteria. Finally, when the completed system undergoes testing, it is necessary that all of the critical
performance criteria be demonstrated by comprehensive system tests.
3.2 Power transfer limits and SCR
3.2.1 Voltage and phase angle stability
In Part I, 3.1 it was shown that consideration of ac voltage stability (also known as the voltage collapse phenomenon) also is relevant to operation of ac/dc systems, particularly at inverter stations. It was also shown
that dc control can prevent voltage instability.
The asynchronous nature of a dc link is independent of phase differences between the ac terminations. Furthermore, converter control can beneÞt the phase angles between generators.
3.2.2 Maximum power curve (MPC) and maximum available power (MAP)
The MPC shown in Figure 3-1 deÞnes the Pd/Id characteristic for dc converters (see Part I: 2.2.2 and 3.1),
and is analogous to the P-V or Q-V curves used to illustrate ac voltage stability. For a given SCR, the MPC
describes the relation between dc current and power for speciÞed initial operating conditions and parameters
of the converter station.
The MPC is derived as follows: for a selected initial operating point (usually with dc power, dc current, and
ac voltage at the inverter ac bus set to 1.0 pu), the dc current is varied while maintaining constant the ac
source voltages, the tap positions of the converter transformers, and the combined capacitance of shunt
capacitors and ac Þlters at fundamental frequency, while the inverter extinction angle g remains set to its
minimum value. As seen in Figure 3-1, this means that the ac converter bus voltage will change. Meanwhile,
the rectiÞer is assumed to cater for dc current changes independent of the inverter performance.
The MPC thus corresponds to a situation where the dc current deviates from an initial nominal operating
point and modiÞes the ac bus voltage within a time scale where generator voltage control, any variable shunt
compensation or tap changers have not yet responded to further inßuence the ac bus voltage. Since it is
assumed that the dc current control acts instantaneously, with the ac system being considered as ThŽvenin
sources, the model can be regarded as quasi-steady-state and does not model fast controlled ac dynamics.
(For a fuller explanation and appropriate ac system modeling, see Part I: 2.2.2 and 2.2.5.)
The peak of the MPC in Figure 3-1 has been deÞned in Part I as the MAP for which dPd/dId = 0. The corresponding current is termed IMAP. Should the dc current exceed IMAP, the slope is negative, implying that the
increase in reactive power consumption depresses the ac converter bus voltage sufÞciently to decrease the
inverter active power, i.e., Pd. Thus, for the selected converter parameters and reactive compensation, MAP
depends on the ac system impedance. It also follows that power control would be unstable for the assumed
conditions (including constant g control) if Id were to exceed IMAP .
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
1.4
)
1.0
DC power (p.u.) (
)
1.2
AC voltage (p.u.) (
MAP
MPC
0.8
0.6
0.4
0.2
0
0
0.5
1
1.5
I MAP
2
2.5
3
Direct Current (p.u.)
SCR = 4.5; Qc = 0.54 p.u.; ESCR = 3.96
= 18¡; Xc = 0.15 p.u.
Figure 3-1ÑMaximum power curve (MPC) and ac voltage
Figure 1
3.2.2.1 Critical short-circuit ratio (CSCR)
For a given dc system, different effective short-circuit ratios (ESCR) (see Part I: 2.2.3) produce different
MPCs and correspondingly different values of IMAP. The borderline ESCR for stable constant power/constant g control is termed the critical ESCR (CESCR), which corresponds to the speciÞc MPC on which MAP
coincides with the actual operating point; i.e., the starting point for constructing the MPC coincides with
MAP at the per unit operating values of dc current and converter ac bus voltage (for example, 1.0 pu dc current and 1.0 pu ac voltage).
For the same dc parameters, the MPC curve for an ESCR above the CESCR would indicate operation at less
than IMAP for the dc current corresponding to the operating point, the difference being an effective margin of
stability for modulating current to achieve power control with constant g. This is an important criterion in
planning either for power modulation to damp power swings in the associated dc system, or to accommodate
discrete increases of dc power above the nominal level.
The CSCR can be derived from the CESCR by adding the per-unit reactive shunt compensation. Since the
CESCR and CSCR deÞne the ac system that would produce them for nominal dc operation, they can be
derived from the dc study parameters (see 4.2.1) without ac system data other than the assumption that the
corresponding ac/dc load ßow provides the desired ac converter bus voltage.
3.2.2.2 Operation with an SCR less than the critical value
The above criteria assume control to keep g constant. Should the SCR unavoidably be less than the CSCR, so
that the operating dc current is greater than IMAP, the prospect of unstable operation may be avoided by one
or more of the following:
a)
144
Retaining power control but achieving it in conjunction with modiÞed inverter control (variable g
above gmin).
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LOW SHORT-CIRCUIT CAPACITIESÑPART II: PLANNING GUIDELINES
b)
c)
IEEE
Std 1204-1997
Fast control of the inverter ac voltage by an auxiliary device such as an static var compensator
(SVC).
The installation of synchronous compensation at the inverter station sufÞcient to effectively increase
the SCR and thereby increase IMAP to exceed the required dc operating current on the new MPC.
3.2.2.3 MPC for a rectiÞer
Equivalent MPCs can be derived for a rectiÞer on the assumption of an initial rectiÞer ac voltage and rectiÞer
control to maintain a constant minimum delay angle (while the inverter controls the current). This would be
of relevance to an assessment of whether there would be any power limitation in this mode (e.g., as a result
of a contingent mode shift).
In view of the above, it can be concluded that MPCs are useful visual indicators and analysis tools in revealing performance criteria relative to low and very low SCRs for preliminary planning.
3.3 Recovery from ac and dc faults
For acceptable performance, it is typically required that the dc system should recover successfully from an
ac or dc fault without subsequent commutation failures. The appropriate recovery time for a dc system is
generally determined through planning studies. It depends on the dc line parameters and other characteristics
of the dc system as well as performance requirements of associated ac systems, when the transient and oscillatory stability criteria of the combined ac/dc system are taken into account.
As a general guide, recovery to 90% of prefault real power transfer level can be accomplished in 100Ð
300 ms if the SCR is greater than 3.0. If the SCR is less than 3.0 after the fault clearing, then the effects of
magnetizing in-rush currents will be larger and recovery will generally be initially to a somewhat lower
power level, typically 80% in 100Ð300 ms, followed by a slower rise towards 100%. A slower recovery, particularly if the ac network has sufÞcient inertia to maintain adequate stability margins, is not usually signiÞcantly detrimental to overall network performance. Too rapid a recovery can sometimes lead to the dc
system drawing excessive reactive power from the ac network, thereby hindering post-fault ac voltage recovery. It should be recognized that often the reactive (Mvar) requirements of the dc station are substantially
supplied by shunt capacitors and the ac Þlters. The Mvar supplied by this equipment is proportional to the
square of the ac bus voltage. This means, for example, that at 0.7 pu ac voltage that is only 49% of the nominal Mvar available at 1.0 pu voltage will be produced by the converter shunt capacitors and ac Þlters, with
any remaining converter Mvar requirements, by necessity, coming from the ac network.
Generally, both the direct current and direct voltage are required to recover within a desired recovery timeframe. While strategies will differ, there is a common goal of ensuring that the rate and time of recovery
assist the return to steady-state conditions and minimize system oscillations. In post-fault conditions, recovery to a different SCR may require additional shunt capacitance in order to maintain dc voltage and power.
Otherwise, operation may be limited to a lower power.
3.4 Reactive compensation
Reactive compensation control is provided at a dc converter station to meet the requirements of ac system
voltage, reactive power exchange with the ac system, or both. SpeciÞc performance criteria are based on
steady-state voltage support, var generation, transient voltage control during recovery from contingencies,
and alleviation of temporary overvoltages (TOVs) in general. Reactive compensation elements include harmonic Þlters, shunt capacitors, and shunt reactors, and, if required, synchronous compensator (SCs) or static
var compensator (SVCs). With an appropriate control scheme, a converter may also be considered as a reactive compensation element that can adjust its reactive power absorption level to assist the ac system.
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One of the dc control objectives could be to maintain the ac voltage within a desired steady-state range. This
can be considered when a low SCR produces a marked ac sensitivity to dc variations. Otherwise, with a
lower sensitivity due to a relatively higher SCR, an alternative could be to maintain a set reactive power.
When the converter is fed directly by a generating station, much of the converter reactive requirement is usually supplied and controlled by the generators.
3.5 Temporary overvoltages (TOVs)
As discussed in Part I, temporary ac system overvoltages can occur at a terminal of a dc system due to converter blocking, ac fault inception and clearing, dc faults, and other disturbances. These overvoltages can be
particularly severe for low and very low SCR applications. Because of the potential for damaging utility and
customer equipment, as well as the impact on dc converter station design and cost, it is essential that suitable
TOV control measures are included in the design.
At dc converter stations, temporary ac overvoltage peaks can be created by superposition of fundamentalfrequency and low-order harmonic voltage components. The fundamental-frequency component overvoltage
is due to the mismatch between the converter station reactive power supply and the instantaneous reactive
demand of the dc converter and the ac system. Fundamental-frequency voltage variations also may occur as
a result of ac generator rotor-angle swings, which may be stimulated by ac faults or dc system power-ßow
disturbances.
Low-order harmonic voltage components, superimposed on the fundamental frequency voltage, often result
in voltage peaks much higher than the fundamental component. The harmonic voltage components are created by interaction between noncharacteristic harmonic currents injected by the converters during disturbances, harmonic currents injected by saturated transformers, and the ac system harmonic impedance.
While it may also be an issue for third harmonic resonance at higher SCRs, the capacitive shunt compensation at the converter ac bus and the relatively high system inductance, for a low or very low SCR application,
typically result in a parallel resonance near the second harmonic. Such a resonance can result in harmonic
voltage components which are substantial relative to the magnitude of the fundamental during disturbances.
The characteristic low-order harmonic resonance and high fundamental-frequency overvoltage levels at low
or very low SCR terminals can combine to create potential overvoltages exceeding two per-unit without mitigation.
It is recommended that criteria be established for the performance of overvoltage control for each dc system.
They determine the levels imposed on the ac system at load buses, affected substations and on lines. Also,
the cost and design of converter station equipment, including valves in particular, are inßuenced by the overvoltages.
Performance criteria have traditionally been speciÞed in terms of maximum fundamental frequency overvoltage values which can be accepted for given periods. However, from the point of view of insulation stress,
or more particularly surge arrester energy, it is necessary to consider the time-varying waveform of TOVs
which include the fundamental frequency component. It should also be noted that in low and very low SCR
applications, instead of the inaccurate use of traditional techniques involving fundamental-frequency overvoltage calculations, it is preferable to use detailed commutation-by-commutation analytical techniques that
faithfully represent low-order harmonic interaction. However, it may be difÞcult to obtain sufÞcient data for
a detailed model at the project planning stage.
3.6 Operation under low ac voltage conditions
Operation under low voltage conditions assumes more signiÞcance due to the increasing sensitivity between
reactive power and voltage as the SCR becomes lower. In order to maintain operating capability, as may be
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determined from transient stability studies, it may be necessary to reduce dc power and reactive power
absorption. Such a mitigating measure may also be appropriate to offset adverse reactive power interaction
during severe ac system contingency conditions, should the SCR become very low.
Available dc technology permits valve Þring for a phase-to-phase voltage at the converter ac bus down to
0.3 pu and possibly lower. An example, from a scheme in operation, is indicative of the criteria for deÞning
low-voltage performance. The equipment at the Miles City and Virginia Smith DC Converter Stations can
meet the following requirements for safe thyristor turn-on and can be considered as being representative:
a)
b)
c)
Voltage reduction down to 0% of nominal for single phase-to-ground faults for a duration of at least
0.5 s.
Voltage reduction down to 30% of nominal for three phase-to-ground faults for a duration of at least
0.25 s.
During ac faults where the measured value of the average 3-phase voltage is greater than 0.40 pu at
the ac converter bus, the dc converter is not allowed to block and must be able to continue to operate
at a dc current up to a maximum value consistent with the thermal limitations of the thyristor valves.
If the measured value of the average rectiÞed 3-phase ac bus voltage is less than 0.40 pu and greater
than or equal to 0.30 pu for a period not exceeding 0.25 s, the dc converter shall not block and shall
be able to continue to operate at a current that may be reduced.
A control function that reduces the dc power in response to speciÞc system events is termed power runback
control. Such a strategy has been incorporated in several dc schemes. In a back-to-back installation it is also
possible to continuously adjust the converter current order and, consequently, the converter direct current in
response to either ac bus voltage variations or the magnitude of an assigned tie-line power ßow. Properly
implemented, such a control strategy would reduce the dc system power transfer to a value compatible with
the ac system capability during low voltage conditions and would prevent cascade tripping of major transmission facilities. The strategy would resume the ordered dc power transfer as the ac system voltage recovers. A similar strategy in a point-to-point dc transmission scheme may or may not be feasible, depending on
the required speed of response relative to communication time delays.
3.7 Power transfer during ac and dc faults
During balanced three-phase faults, the dc system direct voltage is limited by the prevailing ac bus voltage.
The dc system power transfer capability would similarly be limited. During single-phase faults, however, the
imbalanced ac system voltage produces signiÞcant noncharacteristic ac third harmonic currents and corresponding second harmonic dc voltages. The power transfer ßuctuates, as a result, and may be discontinuous.
The average power transfer during a rectiÞer single-phase fault can be about one third of the prefault power
transfer. For an inverter single-phase fault, some power transfer may be possible but is inßuenced by possible commutation failures and the precise recovery performance. For both the rectiÞer and the inverter, such
contingency power ßow could be considered signiÞcant and important for overall system security.
In a monopolar dc system, a dc fault causes interruption of the entire dc system power transfer. In a bipolar
dc system, no power transfer may be expected during a bipolar fault. However, during a monopolar fault in a
bipolar dc system, pole power compensation action may be utilized if the dc system has a suitable temporary
overload capability. Such a control action would temporarily increase the power transfer on the healthy pole
to moderate the impact of the pole fault on the ac systems at both the sending and receiving ends. The power
transfer on the compensating pole would be reduced in harmony with recovery of the faulted pole to minimize the disturbance to the ac systems.
The criteria regarding power transfer during fault conditions are determined by the performance of the overall system in maintaining satisfactory frequency and voltage levels during and following contingencies. The
previous considerations may require controlled changes to dc power during the fault and enhanced recovery
strategies.
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3.8 Operation with and without ground return
Typically, bipolar dc systems have been designed with the capability to transfer power over one pole when
the other pole is out of service. The return circuit for such monopolar operation has been the ground for a
short period immediately after the loss of a pole, followed by the unused pole conductor for long-term
monopolar operation when continuous operation with ground return is not allowed.
Generally, for dc operation with ground return, it is required to have appropriately designed ground electrodes at both rectiÞer and inverter terminals. In situations where ground return is not allowed, even for a
short period, an insulated neutral circuit would be required. Another situation for which an insulated neutral
circuit may be an attractive alternative is when the cost of the required ground electrodes is prohibitive compared to the cost of the neutral circuit. In either case, when an insulated neutral circuit is utilized, it is
required to ground the neutral point of one of the converter stations, as the dc reference point. Moreover, it
may be possible to use the station ground mat for this purpose.
It should be noted that the use of the station ground mat may pose a difÞculty involving introduction of
direct current into the associated ac system during a dc fault when ground fault current would ßow through
the station ground mat. Ground fault current would also ßow through other paths consisting of the grounded
neutrals of the converter transformers, the ac system, and the grounded neutrals of neighboring transformers.
Such a current ßow through the ac system may potentially result in transformer saturation and other forms of
interaction with the ac system. For low SCR applications, such problems may be exacerbated, thereby
requiring appropriate design considerations.
3.9 DC line re-energization
Upon detection of a dc line fault, the direct current on the faulted pole is rapidly reduced to zero. In effect
both the rectiÞer and the inverter on the faulted pole are shut down. Following a sufÞcient delay for deionization of the fault arc (usually, within 100Ð500 ms), the dc system is restarted to the pre-fault power transfer
conditions. If the restart attempt fails, additional shutdown and restart sequences with longer delays may be
executed automatically. Furthermore, the last restart attempt can be made at a reduced direct voltage level. If
the fault is persistent, the pole is permanently blocked.
It should be noted that during the above shutdown and restart sequences, the reactive compensation equipment associated with the faulted pole remains on line in anticipation of a successful recovery from the dc
fault. A low or very low SCR creates, therefore, the potential for signiÞcant overvoltage conditions at the terminal ac buses during such shutdown periods. Consequently, coordination of the converter overvoltage
requirements with the number of allowable shutdown and restart sequences is often necessary.
The characteristics of the restart attempts (number, voltage and timing) are usually determined by the dc line
insulation and the stability requirements of the ac/dc system. In the determination of the restart criteria to be
used, consideration should be given also to the possibility of mechanical shaft overstress in any synchronous
machines adjacent to the converter station.
3.10 Overload considerations
The continuous overload capability of dc systems is primarily inßuenced by ambient temperature and cooling system capability. Generally, a system designed to carry the rated power when the ambient temperature
is high, for example 40 °C, can carry signiÞcantly more power when the ambient temperature is lower, provided adequate reactive compensation is available. It should also be noted that, for low or very low SCR ac
system connections, the added reactive compensation may result in a potentially higher TOV duty at the converter terminal, thereby becoming a factor in the equipment design.
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It is often advantageous for a dc system to be capable of sustaining a short-time overload for pole power
compensation and for power modulation purposes. During pole power compensation actions, the reactive
compensation at both ends of the faulted pole generally provides sufÞcient voltage support for the ac systems to permit the overload capability of the healthy pole to be utilized.
On the other hand, for power modulation purposes, the ability of a dc system to utilize its overload capability
depends on the ac system strength at both the sending and the receiving end. For low and very low SCR
applications, coordination of power modulation control and reactive power control is essential. An example
of the limiting situation is when ac system conditions at one end require sudden utilization of the short-term
overload capability, while the other end has a low or very low SCR and cannot accommodate the sudden
power transfer increase over the dc system.
The duration and magnitude of the short-time overload for pole power compensation, following a transient
dc line fault on one pole, may be also deÞned by the requirement to control the overspeed of the synchronous
machines radially feeding a dc system.
3.11 Operation without communication
It has become the generally adopted practice that dc systems are required to perform the basic power transfer
function and all the required protection functions without relying on fast communication between the two
ends. Furthermore, if a dc system performs a special control function that is essential for the overall security
of associated ac systems, the control function must be operational when the communication between the two
ends is out of service. Small signal modulation (within the current margin) should also be operational without communication.
To meet performance criteria at a low or very low SCR converter station, it is necessary for any mandatory
reactive power control to be independent of communication between the two ends.
3.12 Commutation failures
With low or very low SCR operation, strategies can be considered to offset the potential for an increased rate
of occurrence of commutation failures.
Generally, it is a requirement that the converter does not experience commutation failures for frequently
occurring changes in its associated ac system. These include switching of reactive compensation elements as
well as faults and line switching in nearby distribution networks. For infrequent switching events, like energizing the converter transformer or a nearby high-voltage autotransformer, a low probability (less than 10%)
occurrence of commutation failures may be considered acceptable. The use of pre-insertion resistors or synchronized switching may be beneÞcial in avoiding commutation failures.
Should a commutation failure occur, it is necessary to take appropriate control actions to ensure successful
recovery of the dc system and power transfer resumption, without subsequent commutation failures. Some
events can be predicted and action taken simultaneously.
3.13 Voltage changes during reactive switching
The increased voltage sensitivity to changes in reactive power, as the SCR becomes lower, creates a potential
for voltage changes at loads in the vicinity of the converting station when reactive banks are switched. Consequently, the required limit on voltage change to reactive switching may establish the incremental switching size of reactive banks, i.e., Þlters, capacitors, and reactors. Parameters, besides the bank size, that
inßuence the voltage change on reactive switching are as follows:
Ñ
Ñ
The ac system impedance as characterized by the SCR.
The amount of shunt compensation already connected to the bus.
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Ñ
Ñ
Ñ
IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
The pre-switching ac bus voltage.
The amount of power being transferred by the dc converter.
The reaction of the dc system following the switching event, including the effect of control action.
The above key parameters can be considered in establishing appropriate voltage change criteria for a dc terminal and in determining the appropriate sizes of capacitor, Þlter, and reactor banks for the purpose of limiting ßicker. Furthermore, the criterion for limiting the voltage change on reactive switching may also be
based on the following considerations:
Ñ
Ñ
Ñ
The degree of customer dissatisfaction resulting from the voltage change.
The relative frequency of switching events that cause the voltage change.
The relation between voltage changes at the converter commutation bus and the corresponding voltage changes at distribution buses.
A higher voltage change may be permissible during less frequent operation at low power levels.
3.14 Availability (adequacy and security)
When the SCR is low or very low at the point of connection, the dc power may still be a signiÞcant proportion of the total power demand of the ac system. Therefore, the security of the dc system assumes a greater
importance, and system studies and design measures are necessary to minimize the impact of contingency
conditions in order to ensure the maximum degree of availability and compatibility with the ac system.
3.15 Economic and reliability criteria for comparison of different solutions to interaction problems
For the amelioration of any interaction problem, there will be a trade-off between performance beneÞts
(including reliability) and costs. Since interaction in a low or very low SCR situation tends to be more pronounced, the criteria for establishing the trade-offs take on additional signiÞcance.
Consequently, compared to what could be considered as overdesign in converter stations at high SCR locations, the solutions to certain interaction problems, e.g., ac Þlter redundancy, and operation of an inverter at
an increased extinction angle (g) to reduce the incidence of commutation failures, may be justiÞable for a
low or very low SCR application.
The criteria for comparison of alternative solutions may include an assessment of the state-of-the-art, i.e.,
what has been achieved and what is considered as possible, as well as an evaluation of the beneÞts of modifying a conventional approach and the cost of attaining speciÞc aspects of system performance.
3.16 Multiterminal considerations
The Þrst two multiterminal dc systems have evolved from the expansion of two-terminal dc systems; hence,
it is reasonable to assume that some of the existing, as well as presently planned, two-terminal dc systems
may be expanded into multiterminal conÞgurations. In some cases, the expansion will be anticipated and
properly reßected in the original equipment design. In other cases, however, modiÞcations to the two-terminal system will be required to accommodate multiterminal operation. Advanced planning is advantageous in
minimizing required modiÞcations and, thereby, in minimizing outage of the original link during the construction phase of the expansion.
In the context of this guide, whether for expansion or for original multiterminal planning, one or more of the
inverters could be relatively small in power rating (e.g., less than 25% of the total inverter power rating), coincident with operation at a low or very low SCR. Since the interaction at such a terminal would be accentuated
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by the diversion of current from other terminals during certain contingencies, it assumes an additional significance to the previously described performance criteria. Strengthening the ac system and designing the
inverter to operate at a larger g are among options in improving performance.
4. Planning considerations
4.1 General aspects
In evaluating the ac/dc interaction in planning, a low or very low SCR system cannot be characterized only
as a Òhigh impedanceÓ system, but must be further identiÞed as having adequate or inadequate inertia and
high or low damping.
For a high-impedance system (low SCR) with high inertia and high damping (low impedance angle), it is
feasible to rely on dc controls to meet performance criteria.
It may be possible to achieve the same performance criteria in systems with high impedance and high inertia
but low damping, either entirely by appropriate dc control adjustments or with supplementary overvoltage
control devices such as SVC and metal-oxide (MO) surge arresters.
When there is inadequate inertia (see Part I: 2.3), it is necessary to install SCs in order to maintain ac system
voltage and frequency following faults which disrupt the dc power. Compared with a typical generator, SCs
have low inertia; consequently, a higher frequency mode of oscillation may have to be taken into account.
The impact of a prospective dc facility on the overall network performance should be evaluated prior to
project commitment and contract award. Although it is impractical to run detailed studies for development of
the actual dc controls prior to contract award, it is valuable to identify the general overall functional requirements. A number of areas should be studied for all stations, regardless of SCR:
a)
b)
c)
d)
Power transmitted during transient undervoltage and, for a low or inadequate inertia system, underfrequency conditions.
Post-fault power recovery rate and quality of power recovery.
Percentage of power delivery relative to size of the receiving load, particularly for the post-fault line
outage condition.
Desirability of supplemental dc controls such as fast ramping, small or large signal modulation, and
controls to damp subsynchronous oscillations of generator-turbine shafts.
For installations with low or very low SCR levels (less than 3.0) study of (a), (b), and (c) takes on an increasing importance. Item (a) is primarily a function of the system inertia and voltage conditions; and (d) involves
many factors not as directly related to SCR.
As has been pointed out previously, the SCR represents the admittance of the ac system as seen from the
converter ac bus, and therefore, in high impedance applications, it is one of the factors inßuencing voltage
regulation. It will greatly inßuence the size of TOV, the power recovery time of the dc station after ac or dc
faults, the quality of this recovery, and the stability of the dc controls. However, these inßuences must be
thoroughly understood for each project because the SCR is only an approximate indicator in the assessment
of prospective ac/dc interaction.
In the planning studies for a low SCR dc installation (see 6.3.4 and Table 6-1), it is particularly important to
have a detailed knowledge of the ac network and any existing dc systems within it or terminating in it. Based
on the assumption that the dc response is fast in comparison with the dynamics of ac networks, power ßow
and transient stability programs are usually sufÞcient for the evaluation of the basic performance of the dc
system to meet the overall ac/dc system requirements. Following that, unless the planning is conÞned to
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achieving a functional description, further studies may be undertaken of a more detailed nature to arrive at a
speciÞcation. The derivation of the speciÞcation of the various dc facilities, including the dc controls and the
arresters in the dc substation, may involve real-time or computer simulation, in which the dc system and the
three-phase ac network can be represented in sufÞcient detail. Circumstances may also justify the use of
other specialized computer programs, e.g., eigenvalue analysis, harmonic propagation, and long-term
dynamic simulation.
The following time scales of ac/dc interaction are relevant to planning studies:
a)
b)
c)
Hundreds of milliseconds (TOV, voltage stability)
Seconds (electromechanical oscillations)
Steady-state (long-term voltage stability, subsynchronous interaction)
The magnitude of TOV and the speed of recovery of power transfer are of particular importance in low and
very low SCR situations. They warrant careful investigation in the planning stage. Both aspects are affected
by the damping (characterized by the phase angle of the ac impedance viewed from the converter ac bus; see
4.4.1) and the ac system inertia (see 4.3.2). A high-impedance angle is associated with low damping but is
not always quoted with the SCR. Consequently, two systems with the same SCR but different impedance
angles will require different solutions to meet the same overvoltage criteria.
Another important issue in the assessment of TOV is resonance at low-order harmonic frequencies.
Fundamental to all the above issues is the ability for the dc system to meet the scheduled power demands
and any required deviations in power from the nominal operating level. Criteria for assessing the impact of
low and very low SCRs on power transfer limits were explained in 3.2. In 4.2, the corresponding planning
implications are further discussed.
4.2 Power transfer limits
4.2.1 Determination of CESCR and MAP
The critical effective SCR (CESCR) at the inverter station (see 3.2.2) can be calculated from Equations (8)
or (9) of Part I, 2.5. Alternatively, an approximation, which is considered adequate for initial planning, is to
use Equation (3) from Part I, 2.2.1.4 [repeated in Part 2 as Equation (1)] together with Figure 4-1. As before,
the ac converter bus voltage is assumed to be 1.0 pu.
QESCR = ( S Ð Q c ) ¤ ( P d + Q d )
(1)
where
S
Qc
Pd
Qd
is ac short-circuit level
is reactive shunt compensation
is converter dc power
is converter reactive power consumption
As for ESCR, the term QESCR can be considered as having an equivalent critical value (CQESCR). One
advantage of using CQESCR is that it is quite insensitive to changes in extinction angle (see Part I,
Figure 2-11). It serves as an intermediate step in deriving the approximation for CESCR. Figure 4-1 provides
a pre-calculated chart of CQESCR and Qd as functions of the commutation reactance on ac bases. From the
initial dc study data, the CQESCR and Qd are estimated from Figure 4-1 and entered into Equation (1) to calculate (S-Qc). When divided by Pd, it provides CESCR.
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LOW SHORT-CIRCUIT CAPACITIESÑPART II: PLANNING GUIDELINES
1.05
CQESCR
1.0
0.95
CQESCR
Reactive power consumption (p.u.)
0.9
0.85
0.8
0.75
gamma
0.7
20¡
0.65
18¡
0.6
15¡
0.55
0.5
0.45
0.4
10
12
14
16
18
20
Xc Commutating Reactance (%)
Figure 4-1ÑCQESCR
& Qd 2
as a function of Xc
Figure
CQESCR & Q d as a function of X
If the reactive compensation is known, S and hence CSCR can be obtained, as illustrated in the following two
examples:
Ñ
Ñ
For converter data of Xc = 15% and g = 18°, Figure 4-1 provides CQESCR = 0.95 and Qd = 0.54
which, when entered into Equation (1) and assuming full reactive compensation (Qc /Qd = 1), and
Pd = 1.0 pu by deÞnition, give the criteria values of interest: CESCR = 1.46 and CSCR = 2.0. The
latter equals the more exactly derived value.
Similarly, for Xc = 20%, g = 21° and Qc /Qd = 1.5, CQESCR = 1.0 and Qd = 0.65. Hence,
CESCR = 1.65 and (since Qc = 0.98 pu) CSCR = 2.63. The exact value of CSCR is 2.58.
Such derived critical values can now be used for preliminary assessment of the required power transfer capability relative to the predicted SCR.
The MPC may be generated by a load ßow program (with the caution that a given program may not necessarily provide suitable manipulation of the desired variables) or possibly a general purpose mathematical
analysis program. For evaluation for ac/dc performance under a variety of conditions, it is important to
include outage conditions, such as transmission line or compensation equipment outages, in addition to normal operation in deriving MPCs.
The use of a set of power ßow solutions is valid from the assumption that the quasi-steady-state MPC does
not account for fast dynamics, such as the response of generator AVRs, in the ac system representation. The
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generators should be modeled as constant voltage sources behind their transient reactances (see Part I,
2.2.5.2). The essential steps are as follows:
Ñ
Run the ac/dc power ßow for the normal operating point, i.e., with the selected Pd, Id, reactive shunt
compensation, and ac converter bus voltage. This solution also determines the generator voltages
behind their reactances, and the tap positions on the converter transformers, to be kept constant for
the other points on this MPC.
Ñ Without adjusting the shunt compensation device (e.g., maintaining a constant value of shunt capacitance), run the power ßow repetitively to calculate Pd over a range of Id above and below the initial
Id to encompass the MAP point in deriving the MPC.
The resultant normal MPC may be designated MPC-1. For the contingent MPCs, step (2) is repeated, using
the correspondingly modiÞed power ßow, but with retention of the reactive compensation, tap position and
generator voltages from step (1).
An example of a set of derived MPCs is shown in Figure 4-2 (this Þgure is based on Figure 5 in Gavrilovic et
al. [B18]4) for an inverter system in normal operation (MPC-1) and three different ac line outage conditions
(MPC-2, 3, and 4). MPC-1 is a normal high SCR condition with nominal operation well below MAP. With
the MPC-2 outage, operation below MAP and with the original power can be attained by an increase of the
dc current to Id(2). However, the original power cannot be restored in MPC-3 without additional dynamic
voltage support. The maximum power attainable is a MAP of Pd(3) when the current is increased to Id(3).
Finally, for the severe MPC-4 outage, the original current exceeds the new MAP so that rectiÞer power control would immediately have to change to current control in order to maintain stability at a reduced dc power.
Should the system voltages be unsatisfactory, additional measures would be needed in achieving acceptable
performance.
In using MPCs for planning, it should be conÞrmed that the assumption of certain quantities being kept constant in MPC derivation, for normal and contingent conditions, is valid for the particular study. As seen in
Figure 3-1, the converter ac bus voltage decreases as the direct current is increased. Some load ßow programs are optimized on the assumption that the per-unit ac voltages do not deviate substantially from unity.
Therefore, should the ac voltage be typically 0.7 pu or lower, such load ßow programs may not converge to
the correct solution. The maximum direct current for which a point on the MPC can be successfully obtained
is consequently dependent on the numerical methods incorporated into the load ßow program as well as the
detail to which the dc converters are modeled. For most practical needs, it sufÞces to know the MPC for
direct currents up to 20% above IMAP. Should it be of interest to calculate the MPC beyond the range of convergent solutions, assistance from load ßow and dc modeling experts could be necessary.
4.2.2 Implications for planning
Following the derivation of CSCR, the MPCs and the MAP points, the implications for actual ac/dc system
design can be assessed.
Depending on the operating point for full-load dc current relative to MAP on the MPC, consideration should
be given to any implied limitations on dc operation, and requirements for dc controls and type and level of
reactive compensation.
Operation at a current signiÞcantly below IMAP, even during contingencies, implies a high SCR, and it is
unlikely that the control modes (in particular, the economically advantageous inverter control mode of minimum g) would be restricted. Mechanical switching of Þlters and shunt capacitors would usually be adequate
without the need for fast ac voltage control devices.
4The
154
numbers in brackets correspond to those of the bibliography in Annex A of Part II.
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1.4
MPC-1
1.2
1.0
dc Power (pu)
MPC-2
P (1), Pd (2)
d
P (3)
d
MPC-3
0.8
0.6
MPC-4
P (4)
d
0.4
I d (1), I d (4)
0.2
0.0
0.0
0.2
0.4
0.6
0.8
I d (2), I d (3)
1.0
1.2
1.4
1.6
1.8
2.0
direct current (pu)
Figure 4-2ÑNormal
and outage
MPCs
Figure
3
On the same MPC, the excess of MAP above the operating power indicates a reserve of stable power transfer
capability without additional ac voltage control. This margin can also be obtained from the type of curves
shown in Figure 4-3, where MAP and IMAP are plotted as a function for SCR above the CSCR (2.0 in this
case) corresponding to the speciÞed converter data.
As was explained in 3.2.2. for MPC-3 in Figure 4-2, should a contingency shift stable operation in the power
mode to a current exceeding IMAP, and in the absence of fast ac voltage control, ac voltage collapse can be
avoided by a mode switch to current controlÑtriggered, for example, by ac or dc voltage falling below a certain level. Provided that operation at the lower power level with current control is acceptable, it may be adequate to accept the restoration of the ac voltage in due course by AVRs in the ac system for the duration for
the contingency.
Alternatively, with the same contingency, power control could be maintained, but at a lower level below the
contingent MAP until the system has been restored. Another variation would be to use a power controller
with a response sufÞciently slow that it would effectively provide current control until ac voltage controllers
responded to raise the inverter ac voltage.
For a normal operating current above IMAP, due to a very low SCR, stable operation in the power control
mode can be achieved by either
a)
b)
c)
An increase in SCR,
Inverter ac voltage stabilization by fast acting auxiliary equipment, or
AC voltage stabilization by converter control in a departure from minimum g operation.
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1.3
Xc = 0.15 ¯ = 80¡
1.25
= 15¡
= 18¡
= 21¡
MAP (pu)
1.2
1.15
1.1
1.05
1.0
1.5
2
2.5
3
3.5
4
4.5
3.5
4
4.5
SCR
(a)
1.8
Xc = 0.15 ¯ = 80¡
1.7
= 15¡
= 18¡
= 21¡
1.6
IMAP (pu)
1.5
1.4
1.3
1.2
1.1
1.0
1.5
(b)
2
2.5
3
SCR
Figure 4 - Variation of MAP and IMAP with SCR
Figure 4-3ÑVariation of MAP and IMAP with SCR
Should normal stable operation just below IMAP frequently undergo excursions above IMAP, the same strategies may need to be considered. Their implementation is as follows.
4.2.2.1 Increase in SCR by synchronous compensators (SCs)
As an alternative to the construction of new ac transmission capability (or, of course, limiting the dc power
to a lower level), the SCR can be increased by the installation of SC(s). By virtue of their active and controllable voltage capability behind reactance, they are the only compensation device to contribute continuously
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Std 1204-1997
to system strength. Thus, their installation leads to a new MPC which displays an increased MAP. The MAP
and MPC concepts were factors in specifying new SCs for the Nelson River DC System (see 8.11.1).
Of the alternatives, such a measure is relatively costly. However supplementary beneÞts are the reduction of
commutation failures for remote ac faults, improving the waveform of commutation voltage, and raising the
frequency of parallel resonance between the ac system and ac ÞltersÑan issue important to distortion and
overvoltages (see Part I, Clause 5).
4.2.2.2 Operating point stabilization by an SVC
As a normally less costly alternative to 4.2.2, a TCR or SR component of an SVC has, in principle, the
dynamic capability to stabilize power control at a current above IMAP. As opposed to the previous assumptions in the derivation of maximum power curves, the SVC effectively modiÞes the MPC to give a positive
dPd /dId slope for variations around the operating point within its dynamic range. Disturbances beyond the
SVC range require one of the temporary alleviating strategies such as a reduction in dc current, as discussed
previously.
4.2.2.3 Operating point stabilization by converter control
The least costly solution, when planning a new scheme having a very low SCR is to use the capability of the
inverter to control reactive power consumption and thereby the ac voltage, by, for example, control regulation to maintain a set ac voltage or regulation of the dc voltage. In order to provide a dynamic range to both
increase and decrease reactive power, the steady-state g must be higher than the minimum g that was previously held constant. The range may be limited by valve stresses, need for additional reactive compensation
to achieve the required steady-state power factor, and the reduced power utilization of the valves. As for
4.2.2.2, contingent operation beyond the range of the g control requires a remedial strategy.
Figure 4-4 shows the Pd /Id characteristic when the inverter control maintains constant dc voltage at a nominal g of 24°. It is superimposed on the corresponding MPC for g = 18°. The linear and positive slope continues above the previous IMAP until the intercept at g = 18°, beyond which operation reverts to the unstable
region for power control on the MPC. An equivalent characteristic could be drawn for the SVC in 4.2.2.2.
4.3 Electromechanical stability
4.3.1 Power transmitted during faults
In principle, the dc system should transmit as high a power as possible, during an ac fault in the system connected to one dc terminal, in order to
a)
b)
c)
Minimize ac voltage deviations at other terminal(s).
Minimize frequency deviations due to a surplus or deÞcit of power in the system(s) connected to the
other terminal(s).
Reduce the impact of loss of power transfer in the faulted system.
However, the speciÞc circumstances of a project under study may dictate a different strategy. For example, it
may be advantageous to deliberately reduce the dc power to a low level, or even zero, until the ac voltage
adequately recovers, in order to reduce reactive power consumption, so as not to aggravate the low ac voltage situation.
The ability to control dc power is not independent of the ac disturbance. During the fault and recovery periods, the possible combination of low voltage, waveform distortion, and sudden phase shifts in the commutation voltage, depending on the severity, introduces the risk of inverter commutation failure. Consequently, in
planning studies, it is prudent to take into account the possibility that a temporary power control strategy
may be interrupted by commutation failure. Also, for a rectiÞer, a reduced ac voltage may limit the dc power.
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1.6
1.4
1.2
= 18¡
)
)
= 24¡
AC voltage (p.u.) (
DC power (p.u.) (
1.0
0.8
= 30¡
0.6
0.4
0.2
0
0
0.2
0.4
0.6
0.8
1
1.2
1.4
1.6
Direct Current (p.u.)
ESCR = 1.7; Qc = 0.64 pu
xc = 15%
Figure 4-4ÑOperation
Figure 5with g-control
4.3.2 Inertia of the ac systems
As noted in 4.1, the mechanical inertia has a signiÞcance in the consideration of the recovery of the dc system from a disturbance. The extent to which it is necessary to take measures to reduce the time to recover is
closely related to the transient stability of the ac system. In certain situations, with a low or very low SCR
but high inertia, the ac system is able to support a long recovery time (400Ð600 ms) and still have satisfactory performance in terms of electro-mechanical stability. For example, the Miles City back-to-back dc link
(see 8.2) operates with a combination of low SCR and high inertia. It has a recovery time of 500 ms without
impairment to transient stability.
The Itaipu system (see 8.12) is another example. In one operating situation in the development phase, the
SCR was very low but the inertia was high. A recovery time up to 600 ms, from inverter or ac faults, was
found to be acceptable.
When the inertia is inadequate to accommodate the basic dc recovery performance, such as when a dc link
feeds most of the power to an isolated island load, SCs may be considered. Controlled reactive devices, such
as SVCs to enhance ac voltage control, may be appropriate for low but not inadequate inertia.
4.3.3 Rate-of-rise (ramp) and quality of the power recovery
The detailed design of those aspects which inßuence the transient dc performance, and recovery from disturbances in particular (see Part I, Clause 10), are primarily the responsibility of the system designer. They
include consideration of ac and dc resonances, converter transformer saturation, dc line parameters where
appropriate, and dc smoothing inductance. Their simulation, whether in real time or by a computer program,
requires 3-phase models of the main ac and dc circuit components together with detailed representation of
the controls.
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In the preparation of a speciÞcation, prior to the availability of detailed simulation, transient stability studies
can be performed to determine the slowest and, if relevant, the fastest dc recovery characteristics that would
be acceptable to the ac system. The dc response of real and reactive power is represented by predetermined
functions that describe levels before and during the fault, the post-disturbance levels, and the ramp-rates
between levels. Since the purpose is to establish the required dc performance, it is unnecessary to model
either the dc components, the feed-back controls, or commutation failure. The worst cases of permanent ac
faults and line loss are selected, followed by a ramp restoration of the dc system. The simulation is extended
to about 10 s. Repeating the simulation with various ramp rates gives the utility engineer an indication of the
minimum required dc performance and any beneÞts to be gained by further recovery enhancement.
4.3.4 DC power relative to ac generating capacity
With reference to Part I, Clause 7, frequency control, transient stability, and voltage stability are important
considerations when the receiving system is strongly reliant on the dc power infeed. Evaluation of potential
problems in this area can be accomplished through use of conventional power ßow and stability programs.
A series of single-outage (N-1) stability cases can be helpful in determining the post disturbance capacity of
the ac network to handle the dc power.
4.4 Planning considerations of HVDC controls
The dc controls play an important role in alleviating the following (not necessarily in order of importance):
a)
b)
c)
d)
e)
f)
TOV following ac fault clearing
The time taken for ac recovery
The effect of any low-order harmonics, whether arising from the dc or ac system, from interfering
with dc or ac operation
Negative damping of subsynchronous torsional oscillations in nearby turbine-generators
The impact on the ac network of the loss of a dc pole
AC voltage excursions due to changes in dc power
On the well-founded assumption that modern dc controls are designed to operate in a stable manner in low
and very low SCR situations, certain detailed aspects will be deferred to the design stage, at which time the
relevant study parameters will be more clearly deÞned. In the meantime, planning studies can address all the
items with the possible exception of item c) in anticipation of the Þnal design.
4.4.1 Temporary overvoltages (TOVs)
Studies of low and very low SCR systems often lead to the conclusion that TOV problems can be redressed
by an increase in the short-circuit capacity. However, it may be possible to economically alleviate a TOV
problem by appropriate selection and optimization of the dc controls (see Part I: 4.13 and 8.4) except for sustained dc load rejection. The level of TOV is a function of both the magnitude of the ac system impedance
and its angle. A lower impedance and higher damping (smaller impedance angle) tend to produce a lower
TOV level.
Care should be taken to identify the proximity of customer loads to the converter station. Depending on their
location, these loads may be exposed to high ac overvoltages lasting several cycles following converter
blocking or partial load rejection. After ac fault clearance, the temporary condition of excess reactive power
from any shunt capacitors and ac Þlters elevates the ac voltage until the recovery of dc operation.
The dc controls can be used to minimize the TOV resulting from ac faults by the following:
a)
b)
Rapidly restoring the dc power, commensurate with the capability of the post-fault ac system to
receive it.
Temporarily boosting the reactive demand of the converters immediately after the fault clearance.
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c)
d)
e)
IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
Establishing a temporary converter bypass mode during the ac fault. The aim would be to minimize
TOV at the remote converter station, where, despite the disruption of dc power, continued operation
at nominally zero power factor would maintain var consumption. While this strategy can be considered for general application, back-to-back stations are particularly amenable without the need to
communicate between terminals.
Initiating the switching of shunt reactors, capacitor banks, and any (nonpermanently connected)
TOV limiting devices such as special MO varistors.
A response coordinated with other voltage controlling devices such as SVC.
Following a dc line fault on one pole of a bipole, TOV can be controlled by adjustment of the reactive
demand through control action on the remaining pole. For planning purposes, a preliminary estimate of the
(fundamental component of) TOV factor kTOV for full dc load rejection can be obtained from Equation (2)
[see Part I, Equation (27)]:
k TOV = V LTOV ¤ V LO
2
2
4
2
2
= { 1 + 2 ( Z ¤ V LO ) ( P cos f + Q sin f ) + ( Z ¤ V LO ) ( P + Q ) }
1¤2
(2)
where
VLO
VLTOV
Z/¿
P+jQ
is initial per-unit steady-state ac voltage
is per-unit fundamental frequency component of the TOV
is total effective ac impedance deÞned by ESCR = 1/(Z/¿)
is real and reactive power drawn by the converter, where P is positive for a rectiÞer, negative
for an inverter, and Q is always positive.
P, Q, and Z have per-unit bases of rated ac voltage and dc power.
Equation (2) is exact if the effects caused by transformer magnetizing current are neglected, as may be justiÞed if VLTOV is less than 1.2 pu. The curves in Figure 4-5 (reproduced from Part I, Figure 8-5) show how the
fundamental component of TOV varies with SCR and damping angle (¿).
Alternatively, the fundamental frequency TOV levels, without dc restart, can be derived from a transient stability program. The positive sequence network is represented in detail near the dc converters. A series of
power ßow cases are prepared with the dc station represented either as a P+jQ load or, if desired, by a
generic model. With P at the rated real power and Q at (for example) 0.5P, shunt capacitance is represented
at the converter ac terminal sufÞcient to achieve 1.0 to 1.03 pu ac voltage in the power ßow case. The stability case is then run simulating loss of the strongest ac line terminating at the converter due to a close-in
three-phase fault.
The dc station is blocked (if modeled) or the dc ÒloadÓ is tripped following the fault clearing, and the ac voltage is then observed. The simulation need only be run for 50Ð100 ms (3Ð6 cycles) after fault clearing. As
noted in Part I, Clause 8, this approach will not identify effects of transformer saturation on the TOV level or
possible resonances between the converter shunt reactive devices, ac Þlters and the ac network. At present
there are no standards for acceptable TOV. However, planners should be alerted to potential concernsÑfor
example, when the simulation indicates a TOV exceeding 1.15 pu. For very low SCR systems, the TOV
level, without any mitigation, can exceed 1.4 pu, as was potentially the case for several recently installed dc
projects.
A more detailed knowledge of TOV requires a form of detailed electromagnetic transients program.
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LOW SHORT-CIRCUIT CAPACITIESÑPART II: PLANNING GUIDELINES
Pd
V
Qd
Z ¯S
Qc
1.8
REC. ¯ = 75¡
REC. ¯ = 85¡
INV. ¯ = 85¡
1.6
kTOV
INV. ¯ = 75¡
Pd = ± 1 p.u.
Qd = 0.6 p.u.
Qc = 0.6 p.u.
= 18¡
1.4
1.2
1.0
1
2
3
4
5
6
SCR
Figure 6
Figure 4-5ÑSystem
conÞguration
andofresults
of simpliÞed
calculation for
System configuration
and results
simplified
calculation for
overvoltageovervoltage
factor ktov after
blocking,
(Initialblocking
positive sequence
factor
kTOV after
fundamental
frequency fundamental
AC voltage =1 frequency
p.u.).
(initial
positive sequence
ac voltage = 1 pu)
4.4.2 AC recovery
It was noted in 4.3.3 that the maximum permitted dc recovery time from a disturbance, such as an ac fault,
can be derived from transient stability studies. Strategies for power restoration are explained in Part I,
Clause 10. With reÞnement as the control design evolves, studies can optimize the restoration performance
in order to derive smooth recovery with maximum ac system beneÞts.
4.4.3 Effect of low-order harmonics on ac system operation (see Part I, Clause 5)
In the planning stage it is presumed that either additional Þlters can be installed at the dc station or the controller can be modiÞed, and that both of these may be necessary to correct for any adverse ac/dc interaction
arising from low-order harmonics.
4.4.4 DC converter causing negative damping of subsynchronous oscillations (SSOs)
As has been reported in EPRI EL-2708 [B12], 1977 Þeld tests at the Square Butte Project in North Dakota
revealed that a converter station can have a destabilizing inßuence on shaft torsional oscillations. The negative
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damping was found to be a result of the constant current controls of the dc station. The destabilizing inßuence
on rotor torsional oscillations can also appear in the constant power regulation mode.
It was found that an additional dc control loop, called a subsynchronous damping controller, can eliminate
the adverse interaction. It is also known that
a)
b)
c)
Negative interaction is highest with radial connection of the dc station to a machine or group of
machines.
The interactions do not appear to be a problem above 20 Hz for a long dc line or cable scheme.
With proper control of the converter station, there are no adverse effects on the torsional stability of
a machine connected to a series-compensated line.
Torsional interaction has been conÞned to thermal generator units. With regard to hydrogeneration, the large
generator inertia compared with turbine inertia, for low- and medium-speed (low head) units, practically
eliminates torsional interaction with either series compensated ac lines or dc transmission systems. However,
since the respective inertia ratio for high-speed (high head) units may not be large, the potential for torsional
interaction is increased.
A quantitative equation has been proposed as a criterion in identifying generating units and system contingencies requiring further detailed studies:
UIF g = ( MW dc ¤ MV A g ) ( 1 Ð SC g ¤ SC tot )
2
(3)
where
UIFg
MVAg
SCtot
SCg
MWdc
is unit interaction factor of the gth generating unit
is rating of the gth generating unit
is short-circuit capability at the converter commutation bus including the gth generating unit
is short-circuit capacity at the converter commutation bus excluding the gth generating unit
is rated dc power
Studies indicate that if the UIF is less than about 0.1, then the unit in question will not have signiÞcant interaction with the dc system. Since the magnitude of the interaction between an individual generator and the dc
system depends on the value of the ac impedance between them, the interaction is related to the SCR. However, the phase of the interaction (response of the dc system in terms of electrical torque at a particular SSO
frequency relative to the torsional oscillation) determines whether the interaction provides positive or negative damping. The phase is largely independent of ac impedance. Thus, if the dc controls are adjusted to provide positive damping relative to one unit, the phase relations will provide positive damping to other units
over the same range of SSO frequencies. It follows that if the dc controls are designed for the most pessimistic case of a radial dc system, other conÞgurations and ac network variations will be accommodated.
Naturally, if a proposed dc converter station had the prospect of being closely associated with the termination of series compensated ac lines, it would be prudent to consider operation with the system conÞguration
least likely to produce negative SSO damping, irrespective of the application of supplementary dc damping
control.
4.4.5 Loss of one pole of a bipole
In addition to providing ac voltage control after the loss of one pole of a bipole, the remaining pole can be controlled to compensate for the reduced dc power by an increase of its power. Care should be taken in the planning stage to specify such a requirement so that the terminal equipment will be appropriately dimensioned to
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accommodate a short-term or extended overload. Modulation of the real or reactive power may also be superimposed to provide damping of transient electromechanical oscillations.
4.4.6 Transient ac voltage depression
The voltage-dependent current order limit (VDCOL), which is usually included in the converter controls,
reduces the dc current when the dc voltage falls below a pre-set level (typically, 0.7Ð0.9 pu). It will respond
to extended ac voltage depressions at the rectiÞer or inverter, and, depending on the selected VDCOL timeconstants, to transient reductions. As a supplementary override feature, power run-back control (see
Part I: 4.7) can be applied to rapidly reduce the dc power, in response to a measured ac indicator such as a
low ac voltage level. Since the dc response can be predetermined, it is feasible to incorporate this feature,
and the assessment of beneÞts, into planning studies, in anticipation of the control design. For example, the
reduction of real and reactive power may assist in voltage restoration. Also, it can be coordinated with other
reactive power control such as switching of shunt capacitors or reactors, with precautions for discharge of
trapped charge before disconnected capacitors are re-inserted.
4.4.7 Low-order harmonic resonances and transfers (see Part I: 5.3.2)
Based on success in several applications, it can often be presumed, in the planning stage, that problems of
harmonic resonances can be resolved by supplementary dc controls. However, if different possible system
conÞgurations can introduce correspondingly different low-order harmonic resonances, then it may be
appropriate to make the control solution adaptive (Reeve and Sultan 1993 [B57]) or to install additional Þlters. Alternatively, it may be possible to re-tune conventional Þlters to accommodate low-order harmonics
upon the detection of harmonic overvoltages. While the required information for detailed studies may be
unavailable until the control design has progressed, the speciÞcation and design are assisted by the identiÞcation of the system parameters (including harmonic impedances) and operating conditions, both normal
and outage situations, that have a bearing on the prospect of harmonic resonances and ac/dc interaction.
4.5 Planning of ac/dc performance enhancement
Performance enhancement can be summarized in two general categories. Category 1 includes those aspects
requiring measures to minimize negative interaction between the dc system and the ac network. Category 2
contains the enhancements that can be considered supplemental in that they improve the performance of the
ac network but are not necessarily required for acceptable performance of the ac/dc interconnection.
Ñ
Ñ
Category 1: commutation failure and recovery; subsynchronous interaction; temporary and transient
overvoltage; power/voltage instability; control of voltage changes; harmonic interaction
Category 2: dc power modulation; power ramping; continuous ac voltage regulation; short-term
overload
Category 1 aspects can usually be taken care of by supplemental dc controls and, while critical to maintaining proper ac/dc interaction, they should not be overriding in the evaluation of various transmission options.
For low and very low ESCR conÞgurations, the Category 1 concerns should be identiÞed as early as possible, with any additional costs for controls or Þlters attached to the project capital cost estimates.
It is important to study possible resonance conditions for low-order harmonics on both the dc and ac sides of
the dc converter station, and harmonic transfer between them, during normal and outage conditions. The
evaluation of resonance is not independent of the means for reactive compensation. A SC effectively reduce
the ac system impedance viewed from the converter ac bus and increases the natural resonant frequency.
Shunt capacitors in an SVC increase the system impedance. In certain cases, it may be necessary to add loworder harmonic Þlters. By providing resource data for the design of the dc control at the outset, any additional control needs can be accommodated at relatively low cost and in anticipation of commissioning in the
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Þeld. Should there be a possibility of coupling between adjacent ac and dc lines (see Part I, 5.3.3 and 5.3.5),
early consideration is recommended owing to the potential cost implications.
The items in Category 2 can be of more importance than Category 1 in assessing and comparing the planning alternatives. The performance enhancement relies on the inherent speed of control of the dc system relative to the ac networks. In this context, performance refers to voltage stability and regulation, and
electromechanical stability of the area generation plants at fundamental frequency. The evaluation of beneÞts should take into account dc contingencies including commutation failures. For example, should an ac
fault produce a commutation failure and, thereby, a transient dc power interruption, performance enhancement can commence upon dc recovery.
The improvement in ac network performance, such as in transient stability, may be substantial, although it
may be difÞcult to express it in monetary terms.
4.6 Consideration of existing dc schemes in the same system (Reeve and
Lane-Smith [B56])
Further to the previous considerations that apply to all projects where the SCR is low or very low, the presence of existing dc facilities calls for evaluation of the following items:
a)
b)
c)
d)
Interaction between the proposed dc terminal and existing converting stations. The higher the
impedance between the two terminals, the more the individual operation can be independent. Conversely, a combination of a low or very low SCR and low impedance between terminals (for example) will extend the ac/dc interaction (as discussed extensively in this guide) into interaction between
dc terminals.
Special dc controls on the existing scheme. Where supplementary controls are being considered for
such features as power modulation, ac voltage control, power run-back and power ramping rates,
they should be carefully coordinated in order to avoid mutually undesirable degradation of performance.
AC Þlters and resonances. Again, close coordination is required.
Load rejection and common-mode ac disturbances. It is necessary to give particular attention to ac
disturbances, which may result in universal dc load rejection, and to coordinate the recovery.
5. System economics and reliability
5.1 General considerations
The costs of a dc transmission system usually increase if it feeds into or out of a low or very low SCR ac system. Extra costs accrue because of increased rating in equipment for voltage control and reactive power
compensation. During the planning process, studies should lead to identiÞcation of major equipment ratings
and the requirement for spares, based on transmission performance expectations for costing purposes. A reliability and economic assessment should include ac components in order to derive transmission at least cost
and with acceptable reliability.
A proper economic assessment of a transmission system should consider such factors as the following:
a)
b)
c)
d)
e)
164
Right-of-way acquisition and preparation
Site preparation costs
Capital costs of various components
Construction schedule and staging
Installation costs
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f)
g)
h)
IEEE
Std 1204-1997
Interest during construction
Cost of losses
Operating and maintenance costs
Reliability considerations can help establish the rating and conÞguration of the transmission system. Also, in
indicating requirements for spare converter transformers, valve groups, and reactive compensation devices,
there is a cost implication.
5.2 Aspects of alternative solutions to solve ac/dc interaction problems
Recognizing that a prospective dc system cannot be considered in isolation from the overall power system,
the following is a closer look at economic and reliability aspects of both the equipment and the procedure to
control ac/dc interaction.
5.2.1 AC voltage and reactive power control
Fundamental frequency voltage control and reactive power control at or near the ac/dc interface are concerns
for ac systems with low or very low SCRs. Options in reactive power control for the ac/dc interface include
the following:
a)
b)
c)
d)
e)
f)
Switched capacitors, reactors and Þlters
Reactive power or voltage control built into the dc controls
SCs
Thyristor-controlled reactor (TCR) and switched/Þxed capacitors
Saturated reactor and switched/Þxed capacitors
A combination of TCR and thyristor-switched capacitors (TSCs)
Station costs are signiÞcantly affected by the adopted ac voltage control strategy. Extensive system studies
of each voltage control option will identify steady-state and short-time component ratings from which budget prices can be obtained from suppliers. Prime consideration must be given to ensuring that loads in the
vicinity of the converter station are not subjected to damaging overvoltages. Overvoltage criteria selected for
protection of local load and the existing ac equipment will be a key factor in selecting ac voltage and reactive
power control. Effective planning studies will identify steady-state and short-time equipment overload ratings as well as the requirement for spare converters, voltage control, and compensation devices. Due to the
uniqueness of each scheme under consideration, it is not possible to generalize comparative costs with any
degree of conÞdence.
Compensation equipment with moving parts, such as a SC, is more prone to forced outages, and it is conceivable that spare units will need to be installed to maintain acceptable reliability. This can substantially
increase costs. Costs also increase if the unit size of a SC is reduced, resulting in a larger number of units.
The increased cost of smaller units can be offset by the overall Mvar rating requirement when spare capacity
is taken into account. As part of the economic evaluation, the cost of losses should be taken into account for
all compensation options.
A compensator with no moving partsÑan SVCÑhas the potential for high reliability, if its controls, range,
and protection are adequately deÞned and coordinated with ac system conditions.
One economic evaluation study (Nyati et al. 1988 [B44]) indicated that the capitalized costs of compensation
devices over their depreciated lifetime in terms of a percentage of the station capital cost were as follows:
Ñ
Ñ
Ñ
Switched capacitors and Þlters (depending on the number of switches): 8Ð15%
Synchronous compensation (depending on the number of spare units): 32Ð55%
Static var systems: 21Ð33%
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These are typical values based on North American conditions in 1985. It will be realized that the numbers
will vary to reßect changes in equipment costs and capitalized losses.
MO varistors are typically less costly than static var systems or SCs for limiting TOVs but lack continuous
voltage control.
Load ßows and stability studies used deterministically will generate good understanding of how the ac/dc
system should perform. With predetermined criteria, such as acceptable TOV and established system design
contingencies, these compensation devices can be evaluated for acceptable system performance.
5.2.2 Probabilistic reliability analysis of compensation
A truly deterministic or probabilistic study of the reliability of a dc system should include the synchronous,
static, or switched ac compensation equipment, which may consist of several blocks. To ensure that the loss,
due to a forced outage, of one or more compensating elements does not inhibit the power transfer capability
of that dc terminal, provisions for spare compensating capacity must be made in the system design. The
extent of the analysis necessary to determine spare compensating capacity may range from simple rules of
thumb, such as providing one spare compensating unit equal in capacity to the largest block at the station, to
more complex probability analysis. At some dc terminals the number of blocks of compensation may exceed
a dozen when Þlter banks, switched capacitors, and SCs are all part of the reactive power supply.
The application of probabilistic analysis for determining the amount of compensation at a dc converter station should allow for the following:
a)
b)
c)
d)
Frequency and duration of a forced outage of each compensating element.
The duration of reactive power demanded by both the terminal and ac system.
A means of costing the loss of revenue when the dc terminal is unable to deliver power because of a
shortage of reactive power.
Capital cost of installing and operating compensation.
The probability analysis can allow the planner to reduce the possibility of failure to deliver an acceptable
level of power. A more sophisticated approach is to optimize the capital cost of installing and operating spare
compensation against the savings in delivering more reliable power as a result of having the extra compensation available.
5.2.3 Impact on existing power systems
Power system stability (including steady-state, transient, and voltage stability) can be an economic consideration in developing a new transmission line in an ac power system. One question that must be examined is
whether the receiving ac system can accommodate the inßow of power from the dc terminal without degrading ac stability.
Studies should be undertaken to decide whether additional reactive power demanded under these conditions
should be located entirely at the dc terminal, adding to the compensation required for the dc link, or dispersed within the ac system, where it may be more effective.
Another option to be considered in a stressed ac system is the addition of transmission circuits rather than
support by shunt compensation. Series capacitors on ac transmission lines may also be considered, but care
must be taken to avoid ferroresonance with converter transformers if the lines terminate at a converter station.
The rapid change of power, which is possible with a dc link, can be used to advantage in maximizing power
system stability. This is a control function of relatively little capital cost that can permit the dc link to have as
good or better stabilizing power for the ac system as an equivalently rated ac line. The extent to which dc
power can be modulated transiently is a function of the ac system strength at the converter ac bus. Suitable
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controllable compensation will increase the voltage support. If additional compensation is required to
increase the stabilizing power of the dc link over that required for reactive power control, then this adds to
the overall costs of the dc link.
5.2.4 Lower-order harmonics
A combination of a low or very low SCR and undamped ac parallel resonant impedances can create harmonic voltage distortion. Without amelioration, the distortion and consequential performance may be unacceptable following a disturbance such as a fault. In general, provided that the distortion can be contained, a
dc link can operate with very low SCRs, limited only by the response time of the power controller and by the
ability of the ac system and its voltage controllers to receive or deliver the ordered power.
To maintain good ac waveforms, the ac Þlter design is important. When ac system impedances exhibit parallel resonance at very high ohmic values with little damping and a narrow bandwidth, particularly below the
fourth harmonic, there is the potential for inadequate performance of the dc system (see Part I, Clause 5, and
Part II, Clause 4). Alleviation through additional expenditure on Þltering to provide ac harmonic damping
can be considered, further to normal (characteristic harmonic) ac Þlters.
Judicious control design can also be applied to damp supersynchronous oscillations emanating from narrowbandwidth impedance resonances. Attention to the design of Þlters and controls can provide improved dc
system performance: recovery from disturbances, reliability, and stability support to the ac system.
5.3 Reliability and economic aspects of different dc system conÞgurations
5.3.1 General considerations
DC transmission, particularly when it is proposed with new or unique conÞgurations of converters and lines,
is a more recent technology with factors of risk that increase as the SCR reduces. In the past, the decisionmakers needed assurance from their own expert staff, consultants, and equipment suppliers that the proposed
dc system was tenable. Today, new technologies (high-power solid-state devices being a notable example)
are being applied to power systems in general. The conÞdence established through dc transmission is supporting new developments for ac applications.
Economics and reliability play a signiÞcant role in the transmission planning process. The economic assessment of transmission systems is generally straightforward.
Reliability assessment of transmission is not as well understood or accepted. However, it can assist in arriving at the optimum ratings of a dc system. Also, for a low or very low SCR application, reliability is a factor
in the selection, conÞguration, ratings and spares, of ac and dc equipment, such as converter transformers
and var compensation.
5.3.2 Economic assessment with various dc conÞgurations
A dc transmission system, no matter what its conÞguration, consists of basic components such as valve
groups, converter transformers, smoothing reactors, and controls. The assembly of these components into
any workable conÞguration will not change unduly the process of an economic analysis. The more dc converter terminals there are included in a dc system, the higher will be the capital cost compared with an optimized ac alternative.
5.3.3 Reliability assessments with various dc conÞgurations
When complex conÞgurations of dc converters and transmission lines are designed into a multiterminal system, a reliability assessment is not straightforward. Even deterministic analysis of the system availability is
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limited by access to study tools that can accommodate multiterminal dc transmission. Nevertheless, such
tools are available, including computer programs for a probability assessment of multiterminal dc transmission. The main factors affecting the reliability of any workable dc scheme, whether bipolar, back-to-back, or
multiterminal are as follows:
a)
b)
c)
d)
e)
f)
Quality of system design
The performance of a dc link is tied closely to the ac system, its relative strength, and the system
design involving compensation, controls, and protection. A dc link outage, as a consequence of an ac
or a dc fault, will be very much dependent on the quality of system design.
Quality of component design
Frequent component failure as a result of poor design will degrade the overall dc system performance and reliability.
Spares for the major power system components
Spares and redundancy in the minor power system components such as controls and protection
equipment
Replacement times for failed components
Operating redundancy versus switchable spares
A reliability assessment inßuences the economic assessment through its contribution to establishing the
number of spares and determining the ratings of major system components. Spares for wound equipment,
such as converter transformers and smoothing reactors, spare Þlters, and compensation, can be decided on
by judicious analysis of dc link reliability.
As a result of incorporating the dc system into the total reliability assessment, and taking into account the
low or very low SCR interface, acceptable reliability can be related to the number of spares. In addition, it
reveals the reliability aspects of short-term and long-term overload ratings. By the inclusion of the incremental costs of achieving a rating, the optimum rating of a dc link can be selected.
Should the loss of revenue for forced outages not justify offsetting costs of either spares or an increased rating, a lower reliability may be judged to be acceptable.
5.4 Study methods, sources of data, and assumptions
Methods for studying reliability of ac and dc transmission systems have been proposed elsewhere (EPRI
EL-4365 [B13]). Computer programs are being used that can assess the reliability of a power system, including generation and ac and dc transmission. Such programs can model large systems adequately and precisely, but the value of output is only as valid as the accuracy of the input data. Operator error and vandalism
are signiÞcant sources of forced outage that cannot be precisely anticipated in reliability planning studies. It
is usual to ensure that forced outage data used as input to any computer program include an estimate of the
effect of operator error and vandalismÑat least at a level that the utility is prepared to tolerate or expect, or
to a level considered acceptable.
5.4.1 Study methods
The rule of thumb reliability approach is still in use by experienced engineers who make decisions on transformer spares, Þlter spares, spare capacity, and spare compensators using such guidelines as being able to
withstand the loss of one element when another is out for service.
If dc link component reliability data are available and are trusted, a detailed computer reliability analysis can
be undertaken. It is difÞcult, however, to fully anticipate all the consequential outages that may occur when
the SCR is low. Unanticipated contingencies, such as a resonance, may lead to a full or partial dc outage due
to the triggering of protection equipment. Their exposure requires precise simulation studies. Following the
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consideration of various ac and dc disturbances, any unavoidable outage and derating should be represented
in the reliability assessment.
Without supporting digital or physical simulation, computer-based reliability studies can offer a valuable
contribution to the design of the dc link in terms of spares and ratings, if done with insight into the analytical
process of reliability and an awareness of limitations.
5.4.2 Sources of data
There are much more data available on the reliability of ac system components than on dc components
(Canadian Electrical Association Report [B16], Lauby et al. [B38]). Very little is published on the reliability
of dc systems in a form useful to the transmission planning engineer. One forum, the CIGRƒ protocol for
reporting dc transmission outages (CIGRƒ Working Group 14.04 Report [B54] is being revised in a form
more suitable for planning purposes.
Reliability data for dc systems should contain forced and scheduled outage data for valve groups, poles, and
bipoles at the very minimum. It is useful to have outage data for the components that are of most concern in
consideration of spares such as converter transformers and dc reactors. The data should be separated into
converter station and dc line data so that evaluation of stations can be separated from effects of line outages
if needed. AC component outage data may be gleaned from published statistics of ac equipment reliability.
Scheduled outage data is important and the computer program and its data should accommodate such outages accordingly.
Details of methods of reliability study for ac and dc transmission are available in the literature (EPRI EL4365 [B13], Kuruganty and Woodford 1988 [B37], and Burtnyk [B5].
5.4.3 Assumptions
Usually, after all the outage data that is possible to obtain has been collected, some assumptions will need to
be made in the interpretation of the data. First of all, a planning study usually includes equipment not yet in
service. A basic assumption needs to be made regarding the validity of data based on past experiences being
used for some future installation in a new and different conÞguration. Useful reliability studies can be undertaken using presumptions for outage data of components that are realistic, acceptable, and perhaps even pessimistic. In the most crucial situation, conÞdence in the plan, or a decision to re-evaluate with additional
spares, will critically depend on the analysis of the total system reliability.
Often in reliability studies, losses are neglected. However, the shape of the load duration curve is particularly
important. Conditions of load, generation, and transmission may vary so signiÞcantly between seasons that
separate summer and winter analysis should be undertaken.
Some components, such as generators, may have substantial scheduled maintenance times and forced outages, and this should be reßected in the data. The same applies to any forced derating of components and different summer and winter ratings.
The question arises as to whether generation and ac transmission should be included in a reliability study of
dc transmission. When examining the value of spares or increased dc link rating, the reliability of supply to
the load will be most important. All sources of supply to the loads, including ac lines and generation, can be
represented in reliability studies to obtain a better assessment of the global value of dc link spares and
increased dc link rating. For example, there may be little value in maintaining a spare valve group at the dc
link rating if there is already adequate strength and reliability in the ac system to feed the load under emergency conditions.
Certainly, should the concept be under consideration of feeding a dc link directly from either an ac generator
without ac Þlters or a high voltage ac bus, then the generation should be included in the reliability study. If
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total system reliability of supply to the load is the ultimate concern, then all major ac and dc components
should be included in a reliability study of transmission expansion.
Normally, momentary outages are not included in adequacy studies. Only steady-state outages are usually
included. Frequency as well as mean duration of outages are important. A dc link may be very reliable in
terms of total down time due to forced outages but the frequency may be limiting or of greater concern.
There is no simple evaluation of the impact of frequency of outage, but if each occurrence results in load
shedding or extensive rescheduling of generation, the resulting inconvenience may be prohibitive. When the
outage frequency is a key issue, as it may well be for bipolar outages, the acceptable level can be determined
by including reliability studies in the speciÞcation, and making them part of the design of both the ac and dc
systems.
Transmission reliability studies can provide a valuable tool to assist in decision-making. They join with the
loss analysis, power ßow study, power system stability study, and electromagnetic transient or simulator
study in the planning procedures for studying power system expansion.
6. Planning and initial design studies
6.1 Introduction
Without comparing the alternatives for interconnecting two or more ac systems, this clause considers the
studies to be undertaken once a dc link has been selected. Emphasis is placed on low or very low SCR applications.
The aims of this clause are illustrated in the ßow chart in Figure 6-1, which indicates the input data, types of
study, and output data for initial studies, prior to detailed speciÞcation studies.
First, planning studies provide information on the type of compensation, frequency support, and control
strategy to adopt for the project. Then, based on these data, consideration is given to the principal aspects of
the initial design studies in order to deÞne both the main circuit and the control requirements. For each type
of study, this clause will provide some preliminary considerations, the aspects to be considered, the method
and tools to use (including modeling), and the information expected from the study.
6.2 Planning studies
6.2.1 Preliminary data
During preliminary studies, the determination of the following items provides a basis for estimating the
impact on the ac system:
a)
b)
c)
The rated power
The ac bus voltage at the point of connection
The target availability and reliability values
The ac data that are needed for ac/dc system studies are discussed in 6.4.
6.2.2 Preliminary considerations
It does not generally require sophisticated tools in order to expose any potential problems needing consideration before the detailed deÞnition of the dc system. Moreover, simple criteria are available for a Þrst evaluation, as explained in Clause 3 and Clause 4.
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ac System
Data
General
Requirements
Possible
Solutions
Planning
Studies
Detailed
Requirements
Planning Tools
A Type
of Compensation
Frequency Support
Controls
Initial
Design
Studies
Specific Tools
dc
Control
Requirements
Main
Circuit
Definition
State
of the
Art
Detailed
Studies
Specific Tools
Figure 7
Planning and Initial design studies flow chart
Figure 6-1ÑPlanning and initial design studies ßow chart
6.2.2.1 Short-circuit ratio (SCR) and maximum available power (MAP)
The SCR is a good indicator of the extent of planning studies that may be required to be performed. Together
with the consideration of operation relative to MAP (see 3.2 and 4.2), it is a basis for preliminary selection of
reactive compensation devices, overvoltage limiters, and the control strategy. As recommended in Part I,
2.2.1.3, the operating effective short-circuit ratio (OESCR) should be considered when the dc link is not
operated at full power under extreme ac system contingencies.
6.2.2.2 Parallel resonance
Equation (4), which is extracted from Part I, 5.5, provides a preliminary indication of the frequency of the
Þrst parallel resonance (fres) between shunt capacitance and the ac system:
f res = f 1 ( SCC ¤ Q c )
1¤2
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where
f1
is fundamental frequency
SCC is ac short-circuit MVA
Qc is Mvar of shunt capacitance (including Þlters)
Assuming a ratio in the range 0.5Ð0.6 between the reactive and the active power of the converters, and full
compensation of the reactive power by Qc, low-order resonance can be exposed.
Further reÞnement can be achieved by the use of frequency scan programs, or EMTP-type studies, for different combinations of shunt capacitance, Þlters, and ac system operating conditions.
6.2.2.3 Effective inertia (Hdc)
The Hdc ratio (deÞned in Part I: 2.3.2) is an indicator of potential frequency control problems, the requirements for fast or slow power recovery, and strategies for var compensation.
6.2.2.4 Unit interaction factor (UIF)
The values of the UIF in the different conÞgurations of the ac system will anticipate risks of subsynchronous
resonance problems (see Part I, Clause 6).
6.2.3 Aspects to be considered during planning studies
6.2.3.1 Frequency support
While slower than SVC for voltage control, SCs have the advantage of energy storage and the provision of
transient commutating voltages during disturbed conditions, even when the SCR is very low. Moreover, they
may be the only means of avoiding frequency collapse in an island ac system in certain circumstances. Various combinations of available designs and their control are available to give different performances in terms
of speed of response, overload capabilities, losses, and reliability.
6.2.3.2 Compensation of reactive power
The choice of a compensation and control strategy will be of major importance for all the other aspects to be
considered in the planning and initial design studies. The following are possible strategies:
a)
b)
c)
Shunt capacitors. They may be designed to provide the total, or a part, of the reactive power
absorbed by the converters. They can be apportioned to ac Þlters (as the capacitance at fundamental
frequency) and to shunt capacitor in several banks generally switched by circuit breakers. They will
be applicable whenever the voltage control at the converter ac bus does not need to be fast.
SVCs. Equipment like saturated reactors (SRs), TCRs, TSCs, or any combination of them, can be
used to provide faster voltage control and improve voltage stability. Switchable reactors may also be
required in some cases.
Combinations of SCs and SVCs. A possible solution to a given compensation problem can be a combination of an SVC, for fast voltage control, and a SC, to increase the ESCR.
6.2.3.3 Converter controls for ac voltage or reactive power control
Converter controls can be an adequate and fast means to maintain the ac bus voltages, or to control the reactive power interchange at the converter bus between required limits, during transients. Back-to-back dc links
are more likely to offer this possibility through close coordination between the rectiÞer and inverter, but the
approach has been applied to long-distance schemes.
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This may be more economical than the installation of static or rotating equipment at the converter bus, even
if the requirements lead to an increase in converter ratings.
6.2.3.4 Temporary overvoltages (TOVs)
When the SCR is low or very low, the need to limit TOVs may signiÞcantly inßuence the station design in
terms of ratings, and in terms of both the overload capability and control performance of the converters and
the compensation devices (see 6.3.3.2).
6.2.3.5 Overload requirements
Because of the inßuence on the station design, including converters, transformers, and compensation, the
need to accommodate overloads should be considered from the outset.
6.2.4 Models and tools for planning studies
The planning tools that are normally used for short-circuit, power ßow, and transient stability studies, with
models valid for power frequency phenomena, are applicable to ac/dc studies provided that adequate converter models are available. Also, for low or very low SCR operation, there should be an adequate control
model, including closed-loop current control, and a model valid for the start up of the dc system after a disturbance. Transfer functions and limits should be included and the dc network should be represented by a
dynamic model, where relevant.
Such modeling is consistent with the other dynamic models (static var systems and excitation systems of
synchronous machines) required for this kind of study.
6.2.5 Information to be provided by planning studies
At the end of the planning studies, and before starting initial design studies, the following data should have
been compiled:
a)
b)
c)
d)
e)
f)
g)
Size and type of compensation (subject to conÞrmation by initial design studies)
Requirements for limiting TOVs
Voltage control requirements
Maximum available power
DC control requirements
Transient overload requirements (long and short terms)
Stability margin
This information is generally sufÞcient to establish a cost estimate, including allowance for any special
requirements.
6.3 Initial design studies
6.3.1 Preliminary considerations
The main purpose of the initial design studies is to produce an exhaustive set of data upon which to base the
speciÞcation. Of principal concern are the deÞnitions of the main system conÞguration and the dc controls.
The studies include ac and dc Þlters, insulation coordination, noise propagation, radio frequency interference, and torsional interaction.
As the planning and design progresses, a point is reached when the typical ac planning tools become inadequate. Since the need for more speciÞc tools is emphasized by a low or very low SCR situation, there will be
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an earlier awareness of any deÞciency. Consequently, while the following issues are described in the context
of initial design studies, they may justify earlier consideration for low and very low SCR applications.
6.3.2 Aspects to be considered in initial design studies
Once the strategies for compensation, frequency support, and dc controls have been selected, new criteria
can be introduced to evaluate with more accuracy the extent of outstanding design problems. These criteria
take into account the actual reactive power provided by static or rotating devices, the actual system inertia,
and the harmonic impedances.
SpeciÞcally, the new criteria are the ESCRs, as a result of the installation of reactive compensation at the
converter ac bus; the effective system inertia, resulting from the installation of SCs, if applicable; and the
effective ac system harmonic impedance proÞle, which is the system impedance in combination with the
reactive compensation and Þlter impedances. They will inßuence directly the choice of a solution satisfying
the various aspects of ac/dc interaction. The main aspects to consider are summarized below:
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Voltage and power stability
TOVs
Transient overvoltages
Harmonic disturbances
Losses
Recovery from faults
System protection
Harmonic stabilities
Subsynchronous interaction
Availability and reliability
A more detailed description of the mechanisms of these interactions is given in Part I.
6.3.3 Solutions to be investigated during initial design studies
Several methods of accommodating interaction problems have already been adopted in existing dc installations (see Clause 8). In this subclause, alternative solutions to various problems will be suggested without
reference to a speciÞc application.
Should there be a termination of another dc system, or another controlled device (e.g., FACTSÑßexible ac
transmission system), in the vicinity of a proposed converter station, it should be recognized that there is a
potential for interaction. It would be prudent to include consideration of such interaction in the following
solution categories, and to select the study tools and models accordingly in 6.3.4 and 6.3.5, respectively.
6.3.3.1 Voltage and power stability
a)
b)
174
Voltage control by shunt capacitors, reactors, and Þlter banks. The switching of shunt capacitors,
reactors, and Þlter banks may provide a solution for voltage control at the ac converter bus, when the
SCR is high but may be limited for low or very low SCR situations. The incremental size and number of banks will deÞne (a) the amplitude of the voltage change that the ac system will have to withstand during bank switching sequences, and (b) the frequencies of parallel resonance under certain
operating conditions, the lowest being typically the most important.
Voltage control by static compensators (saturable or saturated reactor, shunt reactor, TCR, TSR,
TSC). The transient overload capabilities and the performance of the controls of these devices have a
direct effect on the stability of the integrated ac/dc system. They may be appropriate for low SCR
applications. For a very low SCR (less than 2.0), when operation may be at a current exceeding that
of maximum available power (to the right of MAP), the TSC may have an inadequate dynamic
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c)
d)
e)
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Std 1204-1997
response. Special care should be given to the possibility of interaction problems between the converter controls and the SVC controls.
Voltage control by a SC. In some cases, stability problems can be solved by the selection of the SC
parameters, such as the speed of response of the excitation system and the overload capabilities.
Choice of compensation. In addition to being a variable source of reactive power, a SC increases the
ESCR, reduces the TOV, and increases the natural frequency of the system. An SVC has a faster
response, but the reliance on shunt capacitance for var generation reduces the ESCR. The range of
both can be extended by additional mechanically switched capacitors.
Converter control. One approach to resolving interaction and stability problems is to modify the ac
system, such as by adding transmission capacity to increase the SCR, insertion of series capacitors
and shunt compensation at strategic locations, and the enhancement of generator controls. However,
it is technically and economically attractive to consider the exploitation of the converter controls to
control ac voltage (as in 6.2.3.3), damp power oscillations and to control frequency. For example, in
back-to-back schemes, where active and reactive powers can be controlled rapidly without communications and dc line time constants, this solution will generally be preferred economically, compared with extensive ac system modiÞcations or the installation of static compensators.
6.3.3.2 Temporary overvoltages (TOVs)
As a result of fault clearing, load rejection, or a dc line fault, TOVs will occur at the converter ac bus. Fault
clearing may be considered the most onerous due to transformer saturation effects. If it is speciÞed that valve
commutation must resume with minimum hesitation when a fault clears, the control, to the extent permitted
by a speciÞed dynamic margin, can be called on to control overvoltages. Other solutions can be investigated
to reduce TOVs:
Ñ
Ñ
Ñ
Ñ
The reactive shunt compensation can be designed with overload capabilities.
Reactors switched by circuit-breaker or solid-state switches.
MO voltage limiters set at a low protective level, and with a large energy absorption capabilityÑ
coordinated with converter control, if required.
Circuit breakers capable of opening safely under high TOV conditions have also been used to allow
fast tripping of the converter and compensation equipment.
6.3.3.3 Transient overvoltages
Measures to limit temporary and transient overvoltages (lightning and switching) by voltage limiting
devices, e.g., MO varistors, can be coordinated. Breaker pre-insertion resistors and point-on-wave switching
devices are ineffective in limiting magnetizing inrush current transients following fault clearance.
6.3.3.4 Harmonic disturbances
The design of the ac Þlters will be inßuenced by other dc terminals in the vicinity. High Q Þlters may
become overloaded when in proximity to a terminal containing low Q Þlters. Further to the need for effective
ac and dc Þlters, the harmonic performance will be enhanced by the minimization of non-characteristic harmonics. Since harmonic interaction may be emphasized by a low or very low SCR, particular attention
should be given to the converter controls, SVC controls, and tolerances in the reactances of the converter
transformers.
6.3.3.5 Losses
Losses can be managed by adequate speciÞcation of the main equipment, and during the design of the converter transformers, valves, and Þlters. In Þlter design, there is a compromise between high damping and low
losses.
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The control strategy and its consequences on operating angles of converters have a large impact on losses
and have to be considered in the selection of the nominal operating angle.
6.3.3.6 Recovery from faults
During design studies, the faults to be considered on the ac system side are single phase, three phase, remote
or local short-circuits. On the dc side, pole or cable short-circuits have to be considered.
The response of the integrated ac/dc system to a fault will be inherently limited by the power circuit characteristics, but the quality of this response in terms of reliability will depend directly on the adopted control
strategy for both the converters and the compensation, and on the settings of the control parameters.
The valve design can also inßuence the recovery, if operation for under and overvoltage conditions is made
possible.
6.3.3.7 System protection
The introduction of a dc link with its compensation equipment can have adverse effects on ac protection. For
example, when the dc link feeds a system with little generating capacity, the fault levels may be insufÞcient
for conventional protection. At the same time, the combination of shunt capacitance at the converter bus and
a low or very low SCR can modify the fault current proÞle and cause protection maloperation due to the
waveform distortion mainly associated with low-order harmonics.
The solution is normally a change in system protection settings resulting from detailed studies. The introduction of synchronous compensation for other purposes could provide adequate short-circuit current to the
existing protection. However, this would not be an economic solution to the protection problem alone.
6.3.3.8 Harmonic instabilities
This is generally solved by modiÞcations to the controls of the converters or the static compensator, either by
introducing supplemental loops or by adjusting the settings of the control parameters. Where more than one
low-order harmonic resonance is possible, in some circumstances the temporary retuning of a conventional
Þlter may be a solution. (See also 4.4.7.)
6.3.3.9 Subsynchronous interaction
Any potential for the dc system to produce negative damping of subsynchronous oscillations can be accommodated in the design of the controls for the converters, static compensators, and machines, as appropriate.
As a back-up, protective relays, based on monitoring of torsional oscillations, can be considered for the
machines.
6.3.3.10 Availability and reliability
When a dc link is designed to feed power to a low or very low SCR location, the target values for reliability
and availability may be higher than for power interchange between strong systems. To reach high levels of
availability, possible considerations are:
Ñ
Ñ
Ñ
Ñ
Ñ
176
The main circuit conÞguration (one or two poles or bipoles)
The spares strategy
The use of components with high reliability
The use of redundancy
The control design
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LOW SHORT-CIRCUIT CAPACITIESÑPART II: PLANNING GUIDELINES
6.3.4 Methods and tools for planning and initial design studies
In order to study the various phenomena over a range of frequency and time-scales, several tools are needed
for the initial design studies. Most of them are familiar to ac system analysts. Other tools are speciÞc to dc
transmission.
Table 6-1 gives the tools that are appropriate for study and design purposes for each phenomenon.
Table 6-1ÑTools for planning and initial design studies of an integrated ac/dc system
1. Load ßow program
2. Transient stability program
3. AC/DC simulator
4. Electromagnetic transient program
5. Transient network analyzer
6. Harmonic generation and propagation program
7. Frequency response/scan program
Tool
Phenomenon
Voltage/power stability
1
2
3
4
XX
XXX
XX
XX
X
XX
XX
XXX
X
XX
XXX
XXX
X
XX
XXX
XX
XXX
XXX
X
XXX
XXX
TOVs
Recovery from faults
Transient overvoltages
System protection
Harmonic instabilities
XX
Harmonic disturbances
Subsynchronous interactions
5
XX
XX
6
7
XXX
XXX
XX
XXX
NOTEÑThe number of Xs indicates the efÞciency of the tool to study the phenomenon.
6.3.5 AC system and converter station representation in initial design studies
A variety of models is required to accommodate the range of electromechanical and electromagnetic studies.
For a complex system, it is necessary to determine the limits and accuracy of model needed for each study,
and the validity of any simplifying assumptions. The following suggests how, and in what degree of detail, to
model the ac/dc system in this stage of a project.
6.3.5.1 Voltage and power stability
This can best be studied digitally. The system representation must be as complete as possible, including all
the generators that are connected at the nearest substations. Load impedances can be represented at the fundamental frequency. The dc link and compensation devices can be represented as controlled active and reactive power sources. The control regulators must be represented at least in steady-state. Special attention can
be given to the calculation of the commutation margin angle of the inverter, so that the computation can be
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terminated when the margin is violated, being indicative of a commutation failure. The modeling can be an
adequate approximation in such cases. A more accurate representation of commutation failure requires
detailed transient analysis.
6.3.5.2 Temporary overvoltages (TOVs)
The representation of converters as active and reactive loads, based on the steady-state converter equations,
is generally sufÞcient to simulate the steady state or the blocked state of a dc link. The fast response of the
control of compensation device controls on overvoltages must be represented. The parameters determining
the ac harmonic impedances, particularly at low-order frequencies, should be known in detail. Should it be
contemplated to use the converter for voltage control, it will have to be represented in corresponding detail.
Similarly, for the application of switched MO voltage limiting devices, the converter controls should also be
represented to deÞne the proper switching sequence and MO device ratings. Nearby generator excitation
control systems should be modelled as well as load response to voltage.
6.3.5.3 Transient overvoltages
This case is very similar to the previous one as far as modeling is concerned. The generator models should
reßect subtransient reactance to the excitation controls vs. transient reactance for TOVs.
6.3.5.4 Harmonic disturbances
The harmonic impedance of loads should be correctly represented as far as practicable. The proportion of
passive loads and rotating loads can have a signiÞcant effect on the study results.
6.3.5.5 Recovery from faults
For studies of the recovery of converters from faults over a period of typically 300 ms, real time simulators
are commonly used. It is usually sufÞcient to represent machines, including local generators, by Þxed
ThŽvenin equivalents.
For the longer time scales of ac system recovery, computer studies are normally used; it is then important
that the ac system model can represent electromechanical oscillations, i.e., that the inertias are modeled on
the relevant machines. This is particularly important if a SC is connected close to the converter bus. The dc
controls and static compensators equipment and controls have to be represented, but not in the detail used in
simulator studies. The converters and static compensators can be considered as controlled active and reactive
power sources that match the steady-state control characteristics (e.g., ac voltage/ac current or dc voltage/dc
current). Time constants in implementing the static characteristics have to be taken into account.
Current developments in real-time and computer simulation indicate that there is no clear dividing line
between the applicability of both approaches and to the degree of detail afforded by each.
6.3.5.6 System protection
AC line impedances are normally represented by lumped sections when focusing on protection behavior during faults. The section length will depend on the frequency range of the transient currents and voltages
applied to the relays. Sections of 100 km are adequate below the third harmonic, but shorter sections are
needed for higher frequencies. Detailed modeling is needed for the converters, static compensators, and the
control of both. Certain protection studies may also require a transient stability program complete with a
detailed dc model.
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6.3.5.7 Resonances, instabilities, and harmonic transfer
It is important to model the complete controls for the converters and SVCs. A model of the ac system impedance at low-order harmonics should be used. Also, if applicable, changes in the characteristics of re-tuned ac
Þlters (see 4.4.7) should be modeled.
6.3.5.8 Subsynchronous interactions
In modeling the dc system, it is necessary to include the closed-loop controls, such as the dc voltage and current regulators and g control, together with supplementary controls (e.g., power swing damping control) that
respond to system dynamic events. Any active compensation devices and their controls should also be modeled.
In modeling the ac system, it is necessary to account for the frequency dependence of impedances by the
inclusion of frequency-dependent terms in expressions containing inductance and capacitance. This is not
achieved by a transient stability program that represent transmission system impedances as constant ohmic
values at the fundamental frequency on the assumption that frequency deviations are small. Since subsynchronous phenomena introduce voltage and current components at frequencies signiÞcantly different from
the fundamental (power) frequency, constant fundamental impedance models would introduce errors into
calculation of subsynchronous interaction. The mechanical characteristics of turbine generators either can be
included in the system model or rotor interaction can be calculated separately by consideration of the electrical quantities and mechanical characteristics of each unit.
6.4 Required system data
It is important to Þrst identify the ac system characteristics and operating parameters for each technical problem to be studied. As explained in Part I, each aspect of ac/dc interaction demands a particular set of data.
6.4.1 System conÞgurations
Typically, normal operation is not the most demanding. Consequently, it is necessary to review, in detail, all
the possible conÞgurations of the dc and associated ac systems in order to identify, for each category of
problem, the ac system conÞgurations that give rise to the most onerous conditions, in terms of SCR, harmonic resonance, and inertia. They may arise from the loss of one line or generator (N-1), or from the simultaneous loss of two circuits or plants (N-2), particularly when maximum dc power is still required. The
identiÞed conditions should be deÞned in the performance criteria.
6.4.2 Location of generators and loads
The supporting data, in exposing the proximity of the dc station to consumers and generation, will be a basis
for assessing overvoltages, harmonic levels, and subsynchronous interaction. Any existing dc stations also
have to be identiÞed as potential sources of adverse interactions.
6.4.3 Reactive power balance and voltage control
Information should be obtained on key locations in the ac systems associated with each dc station in order to
assess whether improvements there could economically offset the extent of compensation at the converter
stations. For example, if modiÞcations can easily be made to automatic voltage regulators or other control
loops in generators, existing SCs, or SVCs, they may provide economical solutions to some integration
problems.
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6.4.4 Protection strategy
It is important to know the performance of ac protection. This information will permit the derivation of the
proÞles of ac voltages to which the dc station will be subjected under disturbed conditions. The Þrst set of
protection data concerns the transmission linesÑthe clearing times of various types of ac faults, and any
auto-reclosure data, are necessary in evaluation of the response of the converters. The second set identiÞes
any settings of overvoltage, overcurrent, overspeed, and underspeed protection that may affect the ac/dc
interaction as a result of generator tripping. It is also important to identify any provision for load tripping due
to frequency deviations.
Any protection that separates the ac system into isolated subsystems, following a loss of synchronism of an
identiÞed area, has to be included in the protection list to be provided for the studies.
6.4.5 Recovery from faults
The strategy and ramp recovery rate of the integrated system from ac and dc faults will highly depend on the
requirements for maximum admissible duration of faults and power transferred during faults. A power
recovery proÞle limit must be deÞned for acceptable ac dynamic performance. Generally the response of a
dc link is sufÞciently fast not to interfere adversely with machine swings, and to cause transient instability.
A maximum number of admissible repetitive dc faults (commutation failures) must also be speciÞed as a
result of preliminary stability studies.
Overvoltage limits should also be given as a consequence of the insulation coordination strategy for the ac
system. The duration of circuit breaker clearing and backup must be provided to deÞne the dc power recovery strategy in case of maloperation of ac protection.
6.4.6 Reliability requirements
Since the design of the dc system is inßuenced by the reliability and availability targets, it is necessary to
assemble the relevant data of the following:
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Ñ
Auxiliaries
Redundancy in control equipment
Acceptable outage power for long and short terms
Temporary dc overload capacity
Possible monopolar operation of a bipole
Earth return speciÞcation
Reliability of telecommunications
Spare strategy for HV equipment
Annual maintenance requirements
6.4.7 Cost of losses
The cost of losses should be established in preparation for the selection of a compensation strategy, as well
as the required steady-state or transient performances of the dc link. In long-distance dc transmission
schemes, the cost will also be of major importance in the deÞnition of the dc voltage.
6.4.8 Harmonic distortion limits
Prior to the design of Þlters, and the special attention given to low-order resonances in low and very low
SCR applications, it is necessary to obtain harmonic distortion limits. There is naturally an economic penalty
should an unduly low harmonic limit lead to the installation of additional Þlters.
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7. Examples of system studies
7.1 Introduction
Examples will be summarized from the literature (Hung [B27], Beard et al. [B4], Liss and Smedsfelt [B39],
Kanngiesser [B30], Krishnayya et al. 1984 [B34], McConnach et al. [B41], Klenk et al. [B32], Thio and
Davies 1991 [B63]) concerning the derivation of study criteria, performance analysis, and speciÞcation during the planning stage of low SCR and low inertia dc projects.
McConnach et al. [B41] is an example of reliability and economic comparison studies. Kuruganty and
Woodford 1987 [B36] contains similar studies and can be used as a good example for ac/dc comparison.
7.2 Itaipu transmission system
The Itaipu HVDC transmission scheme consists of two ±600 kV, 3150 MW bipoles, with two 12-pulse converters connected in series in each pole. It transmits power from nine 700 MW, 50 Hz generators at Itaipu
hydro generating station to the Ibiuna (formerly Sao Roque) converter station in southeastern Brazil, over a
distance of 800 km. The converter station at Foz do Iguacu (sending end) is connected to the 500 kV ac bus.
Several 345 kV and 500 kV lines from the Ibiuna station feed power to the load centers in southeastern Brazil
(see 8.12).
The digital and simulator studies, which were mainly to establish the characteristics of reactive compensation
to be used in Itaipu, are described in detail in Peixoto et al. 1980 [B49]. This comprehensive study includes
all the main aspects that should be examined in planning long-distance dc transmission terminating at a low
SCR location.
The paper discusses the study design criteria, including, in particular, items related to low SCR systems such
as TOV limits, recovery times, and resonances.
7.2.1 Digital studies
Digital studies were performed to determine the overall performance of the system. The paper discusses
means to represent the dc controls and their implication on different aspects of system performanceÑa typical difÞculty at the outset of system planning.
A major requirement of the digital studies was to evaluate the effects of the assumptions made in relation to
the dc control system behavior. For low SCR systems, the most important effects to be analyzed are bypass
or blocking for faults at various ac system locations; recovery rate following bypass operation or blocking;
supplementary stabilization signals; control modes; and the number, initial operating conditions, and rate-ofresponse of dynamic reactive supply equipment. In the study of the dynamic stability of the Itaipu system,
some of the assumptions were given particular attention, such as recovery rate after faults; control mode
(constant power or constant current); rate and response time of the reactive equipment; VDCOL characteristics; and modulation and blocking criteria.
The following aspects of the TOV problem were also examined in Peixoto et al. 1980 [B49]: the type of disturbance to be considered, critical load and operating conditions, and the effects of the different types and
the characteristics of reactive equipment (synchronous and static compensators, and combinations of both).
7.2.2 Simulator studies
To supplement the digital studies, investigations were carried out on a dc simulator to examine the following
items: the effect of commutation failure during recovery; the relation between the rating and response time
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of reactive support equipment, on one hand, and the recovery rate, on the other; and the interaction between
reactive equipment control and dc control.
The different dc and ac system representations (static and dynamic), which were used in the studies, are also
discussed, as well as the quality of the recovery in terms of its acceptability, the effect of some protective and
restoration sequences, the stability margin of the valve group control, and the inßuence of ac system representation on the study results.
A major part of the discussion on simulator studies deals with the selection of the reactive compensation,
i.e., a SC, a SVC, or a combination of both.
7.3 Chateauguay (Hung [B27])
The Chateauguay back-to-back converter station consists of two completely independent 500 MW, 12-pulse
units. It is supplied at 315 kV from Hydro-Quebec (HQ) and at 120 kV from the New York Power Authority
(NYPA) (see 8.5).
The New York side of this back-to-back dc station between Quebec and the State of New York has a low
SCR, while the SCR on the Quebec side is high. Hung [B27] initially examines the reactive compensation
requirements for the project, particularly the needs of the inverter (New York) side due to the low SCR that
can fall to 2.7. From this study it was concluded that an SVC should be used.
Next, the paper describes the simulator studies of the steady-state performance of the interconnection, its
recovery from faults, and its performance after load rejection. The modeling of the ac and dc system components and the converter controls is discussed in some detail in the context of low SCR. Of particular interest
is the discussion on the second harmonic content of the overvoltage after load rejection. Comparisons are
made between SVC and shunt capacitors, and between TSCs and TCRs.
7.4 Highgate
This is a 200 MW monopolar back-to-back interconnection between Hydro-Quebec and the Vermont Electric Power Company (VELCO) (see 8.4).
SigniÞcant low SCR aspects of the planning of this back-to-back project are provided in Johnson et al.
([B28] and [B29]). This paper is of particular interest because it documents the solutions adopted in accommodating very low values of SCR without the installation of SCs or SVCs for reactive support.
The paper concentrates on the studies and remedies used to correct the voltage regulation and the TOV problems resulting from the very low SCRs. In addition, the paper deals with simulator studies of dynamic performance.
The discussion deals with the voltage regulation requirements of the ac systems under steady-state and
switching conditions in order to establish the design criteria. Then, overvoltage conditions are discussed in
terms of circuit breaker transient recovery voltage requirements under load rejection overvoltages; energy
requirements of surge arresters; maximum overvoltage acceptable to the customers; and the need to replace
lightning arresters installed in some of the nearby substations.
It also describes the control and protection philosophy used to comply with the requirements of the ac systems with respect to steady-state voltage control, overvoltages, and dynamic performance.
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7.5 Gotland
The Gotland HVDC transmission project transmits power through submarine cables from the mainland of
Sweden to the island of Gotland. Gotland I was commissioned in 1954 with a 20 MW rating. The second
link, commissioned in 1983, has a rating of 160 MW. It uses a monopolar 150 kV cable with sea return. The
SCR at the mainland ac bus is high. On the Gotland side, the ac system at the 70 kV connection is mainly
passive. The short-circuit capacity is primarily contributed by four SCs, having a total rating of 195 MVA,
which are installed on the 70 kV ac bus (see 8.9).
Liss and Smedsfelt [B39] discusses the different problems that have to be investigated for this type of interconnection such as: frequency control with and without communication, start up of the system, criteria for
frequency control, and performance of the system for small and large perturbations. Some options to solve
these problems are considered together with the basic items in the deÞnition of the rating of the SCs. The
paper also includes some oscillograms obtained in the commissioning tests and from simulator studies,
which give an indication of the system performance.
7.6 Virginia Smith (formerly Sidney)
This 200 MW back-to-back converter station also interconnects the eastern and western ac systems in the
USA (see 8.3).
The criteria and solutions adopted in the design to solve critical interaction problems related to operation
with an SCR as low as 2.25 are described in Klenk et al. [B32]. The paper discusses design aspects of reactive and voltage control, special start-up procedures, and a special scheme for power modulation.
The voltage and reactive control is achieved through converter control by tap changing on the converter
transformers. TOVs are limited to 1.25 pu within 2 cycles by a combination of switchable lightning arresters
(TOV limiters) and bypass operation for faults close to the converter ac bus. A special start-up sequence
avoids the 10% voltage increase produced by switching in the Þlter (105 Mvar).
In addition to the special features related to the low SCR, the paper details the simulator studies of a remedial action scheme (RAS) of power modulation to take care of a potential power-angle instability of the
interconnected system.
7.7 MTDC system studies
Kanngiesser and Ring [B30] and Krishnayya et al. 1984 [B34] describe simulator studies to determine the
performance of a multi-terminal direct current (MTDC) system with small series and parallel converter taps
at low SCR locations. The papers are a good basis to formulate a minimum study program for MTDC planning.
The paper on parallel taps discusses in detail the system operating strategy, the implication of having an
interconnection with a weak ac system, and the dynamic performance of the system for different faults in the
ac and in the dc systems. Different control and protection strategies to improve the system performance and
to protect the small tap are also discussed.
The paper on series taps discusses in detail the ac and dc system modeling and examines different operating
and fault conditions, such as start-up and shut-down of the tap, change of the dc current, change of power
order, and faults in the ac and the dc system. Special restart sequences avoid commutation failures at the tap.
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7.8 Reliability studies
Reliability studies are used in the Þrst stage of the planning in conjunction with economic studies, for comparing ac and dc alternatives, to deÞne the type of transmission to be adopted. Should dc be selected, reliability studies can deÞne characteristics of the transmission scheme such as the number of bipoles, the
number of converters per pole, the extent of spares and redundancy in the converter station, and the type of
reactive compensation (of particular signiÞcance in low SCR applications), as explained in Clause 5.
McConnach et al. 1987 [B41] compares different ac and dc alternatives. Other topics are system performance in relation to transfer capabilities, losses, and operating ßexibility. An economic comparison of the
alternatives is also included.
The studies were carried out using the minimal cut-set technique and examine independent outages, common-mode outages, and overall system reliability. Consideration is also given to the outages due to over-tripping in the ac alternatives, i.e., outages involving a fault on one element and a false trip of another element.
The paper discusses the assumptions to be used and the important topic of the outage data of ac and dc
equipment.
There are other approaches to comparing ac and dc reliability. One of them consists of making the alternatives as equally reliable as possible; the Þnal choice is then based on the comparative costs. Such an
approach was considered in the study reported in (Hardy, Turner, and Zimmerman [B24]).
Kuruganty and Woodford 1987 [B36] describe a methodology to study the reliability of MTDC systems.
7.9 Additional references
Other papers (Frontin et al. [B17], Nyati et al. 1985 [B45], Flueckiger et al. [B15], Lochner and Daehler
[B40], Nyati et al. 1986 [B46], Stemmler [B61], Kaufhold, Peters, and Povh 1987 [B31], Kolodzief, Breuer,
and Hingorani 1985 [B33], Guimaraes et al. [B20]) refer to studies pertinent to this guide. Nyati et al. 1985
[B45] discuss the means to control temporary and transient overvoltages on the converter ac bus, and also
discuss acceptable overvoltage criteria. Lochner and Daehler 1981 [B40] and Nyati et al. 1986 [B46] discuss
the factors affecting low SCR interaction, such as recovery overvoltages, harmonic injection and instability,
and commutation failures.
8. Examples of existing low and very low SCR systems
8.1 Introduction
This clause describes design data and operating experience for some of the HVDC projects that are connected to ac systems at low or very low SCR locations. As explained in Part I, Clause 2, categories of SCR
and ESCR are as follows:
High
SCR ³ 3
ESCR ³ 2.5
Low
3 > SCR ³ 2
2.5 > ESCR ³ 1.5
Very low
SCR < 2
ESCR < 1.5
For typical values of CESCR, PMAP, and TOV, associated with the above system characterization, see Part I,
2.7.
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There are several such dc systems in operation. Most of them have been commissioned since 1980. In some
cases, the design takes into account that a normally high SCR becomes low as a result of a contingency, such
as the loss of an ac line. For example, contingent operation with an ESCR less than 1.0 has been encountered, although, as will be described, it may be offset by a reduction in the dc power transfer limit. As
explained in Part I, 2.2.1.3, the terms operating SCR (OSCR) and OESCR may be used to characterize operation within the normal rating.
In all cases, satisfactory performance has been achieved. Based on experience of these systems, it can be
concluded that a low or very low SCR is not a technical limitation in the evaluation of a dc option in system
planning. For selected dc schemes, it will be described how some of the following concerns, related to a low
or very low SCR, were addressed during planning, preparation of the speciÞcations, and in the design:
a)
b)
c)
d)
TOVs. The problem of TOVs caused by the interaction of ac and dc systems at low or very low SCR
locations, as discussed in general terms in Part I, Clause 8.
Voltage change on switching shunt reactance. Switching of shunt reactive banks causes larger ac
voltage changes as the SCR reduces. To avoid customer complaints, consideration should be given to
the maximum allowable size of shunt reactive bank that can be switched.
Recovery of the dc system from disturbances. This problem, in the context of low and very low SCR
situations, is described in Part I, Clause 10.
Control and system instability. These are discussed in Part I, Clauses 3, 4, 5, and 7.
Table 8-1 presents details of design data for 12 dc systems which have been selected as having a low or very
low SCR under normal or contingency conditions. Included under the latter category is a system condition
called islanding in which the dc converter station, either alone or with a single generating source, becomes
disconnected from the remainder of the ac network
Seven of the schemes are back-to-back converter stations, three incorporate overhead dc lines (one of which
is a three-terminal MTDC system), and submarine cables are used in the remaining two schemes
In addition to the terms SCR, ESCR, OSCR, and OESCR, a further term, critical ESCR (ECSCR), appears
in Table 8-1. CESCRs in the table are calculated for operation at nominal conditions, i.e., for dc current,
power, ac terminal voltage assumed to be at 1 pu, which is consistent with deÞnitions given in Part I, 1.5. For
CESCRs so calculated, MAP coincides with the operating point at nominal conditions (see 3.2.2.1). The
margin between the operating ESCR and the nominal CESCR indicates the amount of additional power
immediately available (see Figure 3-3 and Part I, 3.9). This is an important criteria: a weaker system than the
one corresponding to a nominal CESCR would indicate operation on the ÒunstableÓ part of the MPC. Also,
the relative ac system strengths of different HVDC schemes can be judged by comparing their CESCRs for
nominal conditions. The actual operating ESCRs can be above or below the nominal CESCR, as can be seen
from Table 8-1. For basic characterization of the ac system strength relative to a proposed dc rating, an
appreciation of the SCR may sufÞce. Since the underlying factors for SCR and all the other terms are
implicit in the system data, their calculation, and the concern for the precision of the calculation, is not a prerequisite for system analysis. However, it has been found that their consideration can provide supplementary
insight into, and an aid to the explanation of, interaction phenomena. Thus, after a preliminary assessment of
SCR, the other terms may selectively be considered in a more detailed appraisal of the operating conditions
(see 3.2 and 4.2).
For preliminary planning, the MAP concept (see 3.2.2) can provide some insight into the understanding of
design alternativesÑto supplement, but not to replace, analytical or simulator studies.
From the standpoint of achieving performance objectives, such as ac voltage control while meeting power
control objectives with a margin of security for both normal and contingent SCRs, the planning and design
should not presume preconceived operating modes. It will be evident in the following projects that the dc
control characteristics, and the ac reactive compensation, may well deviate from the basic provision of rectiÞer constant current/power, inverter constant extinction angle, and Þxed ac shunt compensation..
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
8.2 Miles City converter station (Krishnayya et al. 1986 [B35])
This back-to-back converter station (200 MW dc rating) is one of the four dc links connecting the western
and eastern ac systems in the USA. The converter station has a low SCR at both sides, an important aspect in
the design of the system.
8.2.1 Temporary overvoltages (TOVs)
The total shunt capacitive Mvar required for converter operation and ac voltage support is 188 Mvar on the
east side, and 218 Mvar on west side where studies indicated that, without alleviation, this large block of
reactive compensation could result in ac TOVs above 1.55 pu under dc load rejection conditions. The strategy to limit TOV is the combination of an on-line three-phase bank of MO varistors, together with a fast
post-disturbance restart of dc converter to consume reactive power. However, contingent measures, in case
the converter fails to restart, were also considered.
Table 8-1ÑDesign and operating data of HVDC systems connected to low SCR ac systemsÑ
Part 1
Rating
Name of project
AC bus
voltage kV
Year
commissioned
CESCR
MW
kV dc
kA dc
Miles City
(B-B)
200
82
2476
230 (E)
230 (W)
1985
Virginia Smith
(Sidney) (B-B)
200
63
4.14
230 (E)
230 (W)
Highgate (B-B)
200
56
3.6
Chateauguaya
(B-B)
2 ´ 500
140
Blackwater
(B-B)
200
Vindhyachal
(B-B)
Normal system
Contingency
SCR
ESCR
SCR
ESCR
1.8
2.75 (E)
2.00 (W)
1.8
0.9
2.1 (E)
1.5 (W) a
1.2
0.4
1987
1.5
8.6 (E)
5.2 (W)
Ñ
Ñ
2.95 (E)
2.25 (W)
Ñ
Ñ
120 (N)
115 (S)
1985
1.4
2.1 (N)
2.4 (S)
1.6 (N)
2.0 (S)
Ñ
1.0(S)
Ñ
Ñ
3.6
315 (HQ)
120 (NY)
1984
1.7
High (HQ)
7.9 (NY)
Ñ
7.6
High (HQ)
2.4 (NY)
Ñ
2.1
57
3.6
230 (E)
345 (W)
1985
1.5
(Qd = 0.84)
1.9
(Qd = 0.955)
10.1 (E)
2.6 (W)
9.6 (E)
2.1 (W)
4.7 (E)
Less than
1.0 (W)
4.1 (E)
less than 1.0
(W)
Power
reduction
2 ´ 250
139.4
1.8
400 (N)
400 (W)
1988
(EST)
1.6
High (N)
4.4 (W)
High (N)
3.8 (W)
High (N)
1.4 (W)
OSCR =
2.8 (W)
OESCR =
2.2 (W)
Gotland II (cable)
130 ´ 2
150
910
130 (ML)
70 (GL)
1983
1.5
Ñ
Ñ
Ñ
Ñ
Cross Channel
(cable UK
terminal)
2 ´ 1000
±270
1.85
400
1986
1.7
3.0
2.4
2.4
1.9
HQ-New England
(dc line)
Comerford Sta.
690
±450
0.76
230 (HQ)
230 (NE)
1986
1.4
2.3
1.3
Ñ
Ñ
Ñ
Ñ
Itaipu (dc line)
6300
±600
2.625
500 (FT)
345 (TB)
1984Ð88
1.5
2.5
1.9
2.2
1.7
Alberta-Sask.
(McNeil) (B-B)
150
42
3.62
138 (Alb)
230 (Sask)
1989
1.4 (Alb)
1.4 (Sask)
3.3 (Alb)
1.9 (Sask)
2.6 (Alb)
0.9 (Sask)
< 3.3
1.9
< 2.6
0.9
Nelson River BP1
(dc line) BP2
1835
2000
±463
±500
1.98
2.0
230 (DOR)
1972
1985
1.6
2.0 (DOR) c
Ñ
Ñ
3.0 (DOR)
> 3.0
(DOR)
Ñ
Ñ
2.7 (DOR)
2.5 (DOR)
High (ML) High (ML)
1.8 (GL) b 2.7 (GL) b
NOTEÑML = mainland of Sweden; DOR = Dorsey; GL = Island of Gotland; BP1 = bipole 1; BP2 = bipole 2
a 150 MW maximum transfer for west to east direction
b Based on X « of synchronous compensators (2.7 and 2.4,
d
c P = 1.1, V = 0.95
d
186
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LOW SHORT-CIRCUIT CAPACITIESÑPART II: PLANNING GUIDELINES
Table 8-1ÑDesign and operating data of HVDC systems connected to low SCR ac
systemsÑPart 2
AC/DC interconnection requirements
Basic
mode of
control
Xc (pu)
g«min
g«op
500 msÑ90%
PDL
1/, 2/, 3/
0.26
14.5°
15°
0Ð2.99 cyÑ8%
by 3 cyÑ3%
Ñ
1/, 2/, 3/
0.16
17°
18°
TOVfc < 1.35 (N)
< 1.30 (S)
< 1.1 within 15 cy
DV < 2%
100 ms to PL
1/, 2/, 3/
0.13
17°
20°
Chateauguaya
(B-B)
1.4 pu
DV < 5%
400 ms to 90%
PDL
1/, 2/, 3/
0.18
17°
17Ð23°
Blackwater
(B-B)
1.2 pu
DV < 5%
100 ms to PDL 1/, 2/, 3/, 7
300 ms from
power reversal
0.20
17°
20Ð35°@ full load
85°@ Pmin.
Vindhyachal
(B-B)
1.5 pu
DV < 5%
500 ms to 90%
PDL
1/, 2/, 3/
0.19
17°
20°
< 1.3 pu
< 5%
2/, 5/, 6/
0.134
19°
0.5 sÐ1.17 pu
6%
2/, 5/
0.23
15°
15°
1/, 2/, 3/
0.13
14°
18°
320 ms to 90%
PDL
5/, 2/, 3/
0.172
17°
0.25 to 90%
PDL
2/, 4/
0.14
15°
(Alb)
19°
(Sask)
3/
0.20
18°
Name of project
TOV limits
Voltage
excursions
Recovery rate
By 2 cyclesÑ1.4 pu (E)
1.3 pu (W)
250 msÑ1.2 p
0Ð1.99 cyÑ8%
by 2 cyÑ2%
Virginia Smith
(Sidney)
(B-B)
By 2 cyclesÑ1.25 pu
250 msÑ1.15 pu
Highgate (B-B)
Miles City (B-B)
Gotland II (cable)
Cross Channel
(cable UK
terminal)
HQ-New England
(dc line)
Comerford Sta.
< 1.4 pu
Itaipu (dc line)
< 1.4 pu
Alberta-Sask.
(McNeil) (B-B)
0.25 s, 1.4, 0.5 s, 1.3,
1.0 s, 1.2
Nelson River BP1
(dc line) BP2
< 5%
<1.4 pu
19°Ð22.5° (Alb)
23.5°Ð26.5° (Sask)
NOTEÑPDL = predisturbance level; 1/variable g; 2/current control in rectiÞer; 3/power control mode; 4/inverter constant Vd; 5/inverter constant
g; 6/frequency control; 7/constant ac voltage control
The following TOV limits were speciÞed:
Period
TOV Limit
0Ð2 cycles
No limit
2 cycles, 250 ms
1.40 pu west
1.30 pu east
250Ð600 ms
1.20 pu
After 600 ms
Greater of 1.05 pu or ±5% of
voltage before disturbance
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The speciÞc TOV control strategy is as follows:
a)
b)
c)
The initial TOV is limited by customized multicolumn MO devices that have a discharge energy rating of 8.75 MJ. Because they are connected permanently to the ac bus, they are oil-cooled in order to
accommodate the continuous power dissipation at the operating voltage.
The converter operation is restored within two cycles after a fault is cleared to meet the speciÞed
TOV limits by var demand.
The station, including Þlters and shunt capacitors, is tripped if the dc restoration is unsuccessful.
8.2.2 Recovery of the dc power from ac faults
In view of the low SCR, the speciÞcation accepted a relatively slow recovery of dc power to 90% of the predisturbance level within 500 ms, or to a stable but reduced level if required by a very low contingent SCR of
1.5. In the Þnal design, further to the var control of TOV, power is restored in approximately 200 ms, except
for the most severe disturbances. The recovery time is increased to 400Ð450 ms for the loss of key 230 kV
lines on either side. In addition, loss of the east side Miles City-Dawson County 230 kV line requires the
recovery power not to exceed 170 MW for east-to-west transfers. It was found from experience that the
west-side system strength was insufÞcient to support west-to-east transfers above 175 MW.
8.2.3 Voltage changes due to switching
The size of voltage changes, in consideration of their possible impact on local distribution networks, was a
key design consideration. The following limits were speciÞed:
Period
Voltage change limit
(at 230 kV)
Up to 2 cycles
8%
After 2 cycles
2%
The permissible voltage change determines the incremental switching size of reactive banks. The corresponding cost of the reduction in unit size and the increase in switching capability are attributable to the low
SCR. The maximum allowable size of reactive bank that can be switched was calculated to be 15 Mvar
based on the lower SCR on the west side. On-site tests on the east side have shown the actual instantaneous
change in voltage to be 2.2%, well within the 8% limit. The capacitor switching triggers a temporary change
to the delay angle to meet the 2 cycle 2% limit.
In the steady-state, the inverter operates in a regulator control mode to prevent the ac bus voltage from deviating more than 1% from a voltage reference.
8.3 Virginia Smith (formerly Sidney) (Klenk et al. [B32]; Kaufhold, Peters, and Povh
[B31]; DeNomme and Holt [B10]; Piwko et al. [B50])
The SCR at both sides is high (8.6 on the east side, 5.2 on the west side) with full ac transmission capacity.
However, loss of the Sidney-Stegall 230 kV line reduces the SCR on the west side to a low of 2.25. The ac/
dc interaction problems and the adopted solutions, while having many similarities to Miles City, are speciÞc
to this project.
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8.3.1 Temporary overvoltages (TOVs)
The speciÞed TOV limits are 1.25 pu within two cycles, and 1.15 pu within 250 ms. These values are lower
than those speciÞed for Miles City and are achieved by the use of MO varistors that are switched by circuit
breakers. It is necessary to coordinate the varistor switching with other switching actions in the ac system
and with the converter control. The simpliÞed sequence diagram is shown in Figure 8-1.
0
30 ms
Fault detected by protection
system; closing signal to
overvoltage limiter;
initiation of dc bypass
operation
80 ms
Earliest beginning of voltage
recovery
Overvoltage limiter becomes
effective; overvoltage reduced
to 1.25 pu; restart of dc
power transmission
100 ms
180 ms
Successful
dc restart
240 ms
Switch off of
overvoltage limiter
Loading time of
overvoltage limiter
is less than 80 ms
ac system fault
Measurement of ac voltage
peak
Unsuccessful
dc restart
185 ms
Blocking of dc
trip of station
240 ms
Switch off of
overvoltage limiter
Loading time of
overvoltage limiter
is 140 ms
Figure 8
Simplified
operating sequence
of the overvoltage
limiter
Figure 8-1ÑSimpliÞed
operating sequence
of the overvoltage
limiter
The varistor energy rating is based on the optimization of recovery time of the converter, and the station
reactive power requirement. It should be noted that where the Þrst reclosure after a fault is successful, the
varistors are subjected to one sequence of energy absorption. However, they experience a second sequence
when the reclosure is unsuccessful, the line fault being persistent. The varistors at Virginia Smith are
designed to accommodate one 80 ms discharge period (successful dc restart), followed by a second period of
140 ms (unsuccessful dc restart), for a total rating of 28 MJ/phase.
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8.3.2 Power modulation
Studies indicated that, with the dc power contribution to the eastern network, several types and locations of
ac faults resulted in transient stability problems. They were alleviated by dc controls:
a)
b)
c)
The control is provided with power modulation capability to damp generator rotor swings when
power is transmitted from west to east. The power modulation is in response to generator shaft speed
deviations at the Laramie River Station in Wyoming (east side).
The dc power is ramped down to a reduced transmission limit for
1) The loss of either of two key lines on the west side, irrespective of the direction of dc power;
2) An outage of the Virginia Smith-Stegall 230 kV line when the dc power ßows from west to east;
3) An outage of the Laramie-Story 345 kV line when the dc power is from east to west.
Ramping is also used as a backup for the case where the microwave signal between the dc station
and Laramie generating station is lost after the modulation process has been activated.
8.3.3 Harmonic interaction
During the commissioning, a potential for low-order harmonic resonances near the Þfth and seventh harmonics in the eastern network were discovered. To protect the nearby Laramie generator, the dc power is
now interrupted if the Þfth or seventh harmonics are excessive, as indicated by either a sustained Þring angle
imbalance exceeding ±0.2° or by special Þfth and seventh harmonic relays.
8.4 Highgate (Beard et al. [B4], Krishnayya et al. 1986 [B35])
The ESCR can be as low as 1.7 under normal conditions and is accommodated without special reactive
power support, such as SCs or SVCs. The northern ac bus is connected to the Hydro-Quebec system through
a single 120 kV transmission line. The southern ac bus is connected to the single 115 kV transmission line
feeding the Highgate substation on the VELCO system.
8.4.1 Basic control
As for other very low SCR installations, an increase in dc current, as a result of a disturbance, markedly
reduces the inverter ac voltage. In turn, this tends to further increase the dc current, if in the power control
mode, and to increase the overlap angle. Control modes have been selected to moderate such interaction.
SufÞcient dynamic range is incorporated into the Þring angles to provide voltage control with variable g. The
steady-state g is 20° and the minimum g is somewhat less. The dynamic range is effectively extended by the
temporary reduction of current order when there is a severe ac voltage reduction due to an ac fault: the consequent reduction in converter var consumption releases var from shunt compensation to assist the ac voltage
recovery.
8.4.2 DC power reduction
Loss of certain ac lines within the VELCO system reduces the ESCR at the southern commutation bus to
below 1.0 for which there would be the prospect of ac voltage collapse at the converter ac bus in attempting
to maintain rated power. This is avoided by a reduction in the dc power order limit in response to ac line trip
signals.
8.4.3 Control of temporary overvoltages (TOVs)
The prospective low-order resonance between shunt compensation and ac system impedance, and the consequential impact on TOV, is averted by the provision of damped low-order harmonic Þlters.
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IEEE
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8.4.4 Special circuit breakers for capacitor switching
When capacitor banks are tripped to reduce load rejection overvoltages, the circuit interruption must be restrike free. To this end, the circuit breakers, which switch the capacitors at 115 kV, are Þtted with 220 kV
heads. Other circuit breakers, that may be called on to provide back-up service, are installed as a series pair
at each location. Both circuit breakers are tripped and reclosed simultaneously without an additional time
delay for breaker failure protection.
8.5 Chateauguay (Hung [B27]; Krishnayya et al. 1986 [B35]; Hammad, Gagnon, and
McCallum [B22])
On the Hydro-Quebec (HQ) side, the proximity of the 735 kV transmission system provides abundant shortcircuit capacity. On the New York Power Authority (NYPA) side, where there is only one 765 kV link available for transmitting the power to the NYPA system from both the local Beauharnois generating station and
the dc station,
a)
b)
c)
The ESCR varies from 7.6 down to 2.1 for which TOVs and voltage regulation were design considerations;
There is a potential for second harmonic resonance due to the large blocks of required shunt
capacitors;
Precautions are needed against self-excitation and motoring of the isolated Beauharnois units,
should the 765 kV line be tripped.
The solution to a) and b) was the installation of two thyristor-switched capacitor/thyristor-controlled reactor
static var compensator (TSC/TCR SVC) units connected to the 120 kV bus. The SVCs continuously regulate
their reactive power output to match the var requirements of the dc converters and to enhance dc recovery.
The fast SVC response permits the control of transient overvoltages following clearing of ac faults.
SVC control also avoids the potential second harmonic resonance that could be excited by fault clearing.
Upon detection of such a condition, TSC banks are immediately switched off and the TCR branches are
made fully inductive, thereby detuning the system from the second harmonic resonance.
Special measures to prevent self-excitation of the Beauharnois units after the loss of the 765 kV line, include
blocking of dc converters, switching off Þlter and shunt capacitor banks, and tripping the ChateauguayMassena line.
8.6 Blackwater (Krishnayya et al. 1986 [B35])
This 200 MW back-to-back converter station interconnects Public Service of New Mexico (PNM) and
Southwest Public Service (SPS). The SPS connection is through a 230 kV line directly into a large substation and presents no signiÞcant problems of ac/dc interaction. However, on the PNM side, the converter is at
the end of a long 345 kV line which, in the original design, was to be tapped in the middle and connected to
a low short-circuit level 115 kV system. Consequently, there was an original requirement to accommodate a
mainly passive network with a very low SCR after a trip of the remote 345 kV connection.
The potential problems of voltage control have been resolved by the exploitation of the var control capability
of the dc converters. The converters are capable of operating continuously at high Þring/extinction angles
under various dc current loading conditions in order to provide the required control range. Operation is
within the reactive power capability region shown in Figure 8-2.
Capacitance of the ac Þlters and the shunt reactors provides the necessary bias. Switching of these var units
is coordinated by the dc converter controls. The var control capability of the converters is utilized under all
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200
Mvar
Redundant Cooling
100
Normal Cooling
0
0
200
100
MW
Figure 8-2ÑReactive power capability regions of Blackwater HVDC converters
Figure 9
Reactive(loss
power
regions
loading conditions. Under no-load conditions
of thecapability
SPS connection),
the dc terminals are short-circuited and the converters on the PNM side operate exclusively as an SVC to regulate the ac voltage on the
345 kV line.
8.7 Cross Channel (Rowe and Brewer [B60])
This submarine dc link between England and France has a capacity of 2000 MW by two identical but independent bipoles, each ±270 kV, 1850 A dc.
The Sellindge terminal in England has an SCR of 3.0 in the 400 kV network. To regulate the ac voltage, two
SVCs (saturated reactor type), each rated at ±150 Mvar, are connected to the 400 kV bus. They have a substantial short-term overload capacity (3.3 pu for 0.5 s). The TOV at the 400 kV bus is limited to 1.16 pu in
the event of 2000 MW of dc load rejection, when the SCR is at the minimum speciÞed value of 3.0. The four
identical ac Þlters on each pole are switched in response to the transmitted power in order to maintain reactive power balance. In addition, a 200 Mvar shunt reactor is used for voltage control.
8.7.1 Islanding and operation with a passive ac network
The situation of ÒislandingÓ was considered in the design for the event that the Sellindge converter station,
together with a nearby nuclear power station, should become disconnected from the rest of the ac network.
To protect the generators and converters, for this contingency, the converter station is provided with underand over-frequency protection.
Simulator studies also showed that the Sellindge terminal, when inverting, could continue to commutate into
a passive system. This situation occurred following a succession of breaker trips during a storm in January
1987. Figure 8-3 illustrates the performance of the Sellindge converter station following the complete loss of
the ac supply when one bipole was importing 500 MW. The waveforms show that the interrupted commutation during the fault period recovered when the only remaining line tripped. The bipole then re-established
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commutation into harmonic Þlters, SVCs, and the auxiliary load alone. The frequency increased from the
nominal 50Ð57 Hz in about 40 ms. This operated the over-frequency relay. The converter ac bus voltage rose
to 1.5 pu, partly because of the effect of increased frequency on the characteristics of the SVC, and partly
because the SVC was acting in the absence of the ac network.
Outer Group
Valve Currents
Inner Group
Valve Currents
400 kV Bipole
Voltages
Single-Phase
Fault
Fault Clearance
and Converter
Isolation
Valves
Bypass
Bipole
Breaker
Opens
Figure 8-3ÑIslanding of Sellindge (inverting)ÑSVC and ac Þlters connected to bipole
This behavior demonstrates the capability of converters equipped with contemporary controls to invert into
passive networks (the lowest conceivable SCR). As a possible contingency, it should be recognized in the
design of the protective equipment. In such situations, an SVC can still exert some control over the ac bus
voltage, even when disconnected from the ac network, and overvoltage protection can be contemplated for
such a contingency in future schemes.
8.7.2 Second harmonic resonance
No second harmonic problems were foreseen at the minimum speciÞed SCR of 3.0, and no resonant conditions have been encountered in service. However, second harmonic damping was incorporated into the converter controls in anticipation of future changes in the ac system.
8.8 Vindhyachal (Prasad et al. [B53], Rosenqvist et al. [B59])
The Vindhyachal back-to-back HVDC link is comprised of two independent 12-pulse converters, each rated
at 250 MW. It interconnects northern and western regional grids in India. The northern SCR is high. The
western side is connected to the Vindhyachal thermal generating station through a short bus extension. During normal conditions in the initial stages of operation of the dc link, this bus will have a SCR of 4.4.
During the planning studies, it was observed that for a 5-cycle, 3-phase fault at the western ac bus, the
Vindhyachal generators lose synchronism with the rest of the western grid and cause tripping of the Vindhyachal-Korba line. This reduces the SCR on the west side to a low of 1.4 (i.e., to a very low SCR). Studies
also showed that dc power modulation, in response to ac bus frequency, could provide positive damping for
this situation.
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8.8.1 Islanding operation
For dc power transfer, the critical case would occur when the Vindhyachal generators radially feed the converters and become separated from the rest of the western network. Under this islanded mode of operation, a
trip of one or two generators, or one of the two converter units, results in the remaining generators achieving
excessive speeds, if no remedial action is taken. A frequency controller was incorporated in the dc controls
to maintain the generator frequency within the permitted band of 47.5Ð51.5 Hz. The controller, which
responds to bus frequency and acts on the power regulator, is activated for rectiÞer (export) operation only.
The performance of the dc link during this mode of operation and for the worst-case frequency control scenario, i.e. a trip of one out of two Vindhyachal generators, is shown in Figure 8-4. The dc power is quickly
reduced when the frequency deviation exceeds the dead band of the frequency controller, and tripping of the
remaining Vindhyachal generator is thereby avoided.
1.0pu
Un
1.0pu
Uw
1.0pu
Ud
0
1.0pu
Id
0
f
0
-5Hz
P
0
-500MW
0.5
1.0
TIME (s)
Figure 8-4ÑPerformance of frequency controller at Vindhyachal converter station
Figure 11
8.9 Gotland (Liss and Smedsfelt [B39])
On the Gotland side, the SCR and ESCR are 1.8 and 1.6, respectively, based on the transient reactance of the
SC; and 2.7 and 2.5, respectively, using the subtransient reactance. Hence, the SCR can be classiÞed as very
low. It is a good example of how a dc system can feed power successfully to an isolated ac load network.
194
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8.9.1 Frequency control
In the absence of generators, the Gotland frequency is controlled entirely by converter control. Thus, frequency control is the principal function of the master control: the current order transmitted to the rectiÞer
(mainland) is derived from the sum of the set power order and that required for frequency control. To meet
the conßicting requirements of frequency control during steady-state and during transient disturbances, the
controller is provided with a proportional-integral transfer function.
8.9.2 Frequency controller performance
Loss of power transmitted to the island due to a severe fault in the mainland ac system causes a decrease of
frequency on the island. The rate-of-change and amount is determined by the duration of the fault, the inertia
of the SC and the prefault power level. For a 3-phase fault lasting 5 cycles on the mainland, the corresponding duration of island power loss is 0.215 s (see Part I, 9.2.2.1) which is calculated to reduce the island system frequency by 2.3 Hz.
Since the ac buses for both poles are interconnected at the island terminal, ac faults and commutation failures mutually disrupt the total dc power. Recovery from commutation failures is longer due to charging
time-constants of the dc cable compared to overhead line schemes. Nevertheless, the frequency excursion is
reduced by the performance of the SCs during the reduced ac voltage disturbance.
In addition to the procedure for starting and synchronizing of the dc transmission with the island network,
there is also provision for operating the frequency controller without telecommunication.
Thus, among the features of a dc link feeding to an isolated ac network are those associated with the frequency control of the receiving network. Such receiving systems inherently tend to provide a low or very
low SCR, and require moderation in the rate of recovery after ac system faults.
8.10 Comerford (Piwko et al. [B50])
The Hydro-Quebec-New England System Phase 1 project consists of a ±450 kV dc line, 171 km long, from
Des Cantons in Quebec to Comerford in New Hampshire, with a bipole rating of 690 MW. The ac system
voltage at Comerford is 230 kV with a short-circuit capacity of 1600 MVA when all lines are in service. During nominal operation, the converters consume 350 Mvar. However, long lines within the ac system require
additional reactive compensation when heavily loaded in order to maintain ac bus voltages at satisfactory
levels in the vicinity of the converter station. This results in a total installed rating of 819 Mvar from the
combination of shunt capacitors and ac Þlters, and 238 Mvar from shunt reactors. Voltage changes due to
their switching are kept to acceptable levels by the use of relatively small bank sizes.
8.10.1 Control of temporary overvoltages (TOVs)
Consideration of the above parameters indicates very low values of SCR and ESCR, particularly for ac line
outages and when local hydro generators are out of service. Both a model simulator and EMTP were
included in the study.
This system, not surprisingly, exhibited a potential for high TOV which included the harmonic components
contributed by the low natural resonant frequency and the effects of transformer saturation under fault conditions. MO devices were incorporated at Comerford to limit the ac overvoltage to 1.4 pu, with an energy
absorption capability of 20 MJ, as determined by Piwko et al. [B50]. The energy rating provides voltage control, either up to a successful restart or, by default, until relieved by the opening of circuit breakers. For reliability, the MO devices are assembled in four groups per phase with three required for the required energy
rating. They are installed line-to-ground, with 11 parallel columns per group on each phase, and line-to-line
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with seven columns per group. Being permanently connected to the ac bus, the steady-state loss was an
important design aspect.
8.10.2 Control of ac voltage changes
At Comerford, the voltage and current orders, tap changing, and reactive power compensation control are
coordinated to achieve the desired control performance with a concern for voltage deviations. Although a
continuously operating closed-loop ac voltage control function assists in regulating the ac bus voltage, control stability constraints preclude a response sufÞciently fast for voltage deviations due to reactive power
switching. An additional open-loop voltage control function is initiated by the reactive switching. This feedforward action forces the converter Þring angles to a suitable post-switching value by the application of a
pre-determined step to the input of the primary regulator, whereupon the closed-loop ac voltage regulator
can take over. The magnitude of the step function depends primarily on the power direction, the size of the
compensation element being switched, and whether the compensation change is increasing or decreasing the
reactive power on the ac bus.
8.10.3 Power run-back
Loss of a 230 kV line feeding the Comerford station results in an operating SCR sufÞciently low for ac voltage stability to be a concern. An automatic dc power run-back based on the status of ac lines was speciÞed
and installed.
8.11 Nelson River (Thio and Davies [B63])
Bipole I (±463 kV, 1835 MW, 897 km) and bipole II (±500 kV, 2000 MW, 940 km) interconnect separate
rectiÞer stations on the Nelson River to one inverter station in southern Manitoba at Dorsey. The ESCR for
each bipole at the sending end is typically 3.0 (f = 85°) with a minimum of about 2.7 (f = 85°) based on Xd"
of the generators. The design minimum ESCR at Dorsey at the common inverter 230 kV ac bus is 2.5
(f = 80°) based on Xd" of machines, new generation totalling 3500 MW, 757 Mvar contributed by ac Þlters,
nine SCs (six +160/Ð80 Mvar and three newly installed +300/Ð165 Mvar). This is with the simultaneous
contingent outage of one 300 Mvar and one 160 Mvar compensator. Otherwise, the normal operating ESCR
is 3.0 or higher.
8.11.1 Selection of SCs
It was considered that the new 300 Mvar SCs could uniquely strengthen the ac system, as required to accommodate additional dc power, could reduce voltage depressions caused by ac faults, and could improve commutation failure performance.
The compensators were speciÞed to achieve an ESCR of the ac system together with the compensators larger
than the target ESCR of 2.0, when based on Xd«, and 2.5, when based on Xd". Of the two criteria, the former
was selected to ensure operation below IMAP in the context of MAP (see Part I: 2.5, and Part II: 4.2.2.1). In
order to arrive at the used ESCR, Manitoba Hydro developed and used the following approximate formula
for CESCR in planning studies:
2
2
1¤2
P d [ X pu P d ¤ ( 2V cos q ) + ( 1 Ð cos q + [ X pu P d ¤ ( 2V ) ] ) ]
CESCR = --------------------------------------------------------------------------------------------------------------------------------------------V cos q n tan q [ cos q Ð X pu P d ¤ ( 2V ) ]
(5)
where
Pd
V
Xpu
196
is the inverter dc power (per unit)
is the inverter ac bus voltage (per unit)
is the commutation reactance in per unit on the converter transformer base
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cosqn
cosq
tanq
IEEE
Std 1204-1997
is cosg-Xpu/2 = nominal full load power factor of the inverter
is cosg-XpuPd /(2V) = (cosg+cos[g+u])/2
is the actual load power factor of the inverter
Manitoba Hydro claims Equation (5) gives a slightly more conservative (i.e., higher) value of CESCR the
exact (i.e., not approximate) Equation (9) in Part I, 2.5. (System damping is neglected, i.e., f = 90°, in both
equations. See Part I, 2.5, Equation (8), for CESCR with damping included, i.e., f < 90°)
Manitoba Hydro has the requirement that power modulation capability be maintained at Pd = 1.1 pu and
V = 0.95 pu at Xpu = 0.20 and g = 18°, resulting in a CESCR = 2.0 criteria. To achieve rated power at those
conditions, the required CESCR would be equal to 1.6 as indicated in Table 8-1 (i.e., the system could have
been weaker than the criteria selected by Manitoba Hydro).
More recent studies have shown that the response time of the SCs and their controls are sufÞciently fast to
justify the use of a reactance closer to Xd", rather than Xd«, in the context of CESCR.
8.11.2 Control features
In order to avoid voltage instability under certain contingencies of reactive compensation, the dc voltage input
to the dc power control is held at the nominal value, should the measured voltage fall to less than 0.95 pu for
longer than 30 ms (and resets when the restored ac voltage exceeds 0.97 pu for 100 ms). Power modulation,
important for ac system damping, is preserved.
Other special dynamic controls are as follows:
Ñ
Ñ
Ñ
Ñ
Sending end dc power control to control ac frequency while being coordinated not to conßict with
power run-back.
DC power run-back is invoked with a 15 s time-constant for certain receiving end line-trips to prevent cascade tripping.
Power modulation, based on ac bus voltage phase angle, to damp receiving system oscillations up to
3 Hz.
Slower modulation for Dorsey frequency control in islanding situations (with a gain of 0.32 MW/Hz/
MW).
8.11.3 Temporary overvoltages (TOVs)
Ferroresonant sending end overvoltages on energization of sending-end transformers may reach 1.8 pu. The
highest recorded TOV is 1.55 pu. Bipole II transformers are energized through preinsertion resistors.
The predicted TOV at either end with partial load rejection without consideration of transformer saturation,
is about 1.25 pu. The TOV after full-load rejection is initially 1.23 pu (with Xd") and 1.29 pu after 70 ms
(with Xd«). Regulator action reduces the voltage to 1.15 pu within 150 ms.
Of interest to this guide, derived values of TOV and ESCR for the receiving end were entered into
Equation (2) (see 4.4.1) to calculate the ac damping angle to be 80°. In combination with the SCR value, it
permitted the derivation of a simple equivalent circuit of the receiving system, excluding Þlters, for basic
simulator or digital studies.
8.12 Itaipu (Peixoto 1980 [B47], Peixoto et al. 1980 [B49], Porangaba et al. [B51],
Praca et al. [B52], Canelhas, Eriksson, and Pereira [B6])
The importance of moving such a large block of power (6300 MW) (see 7.2), and the prospect of low SCR
circumstances, required extensive digital and simulator studies to deÞne ac/dc interaction problems and to
develop solutions. The lowest studied SCR of the receiving ac systems was 2.2, and the lowest studied ESCR
was 1.7. In service, the minimum OSCR has been 1.8.
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8.12.1 Reactive support and voltage control
Based on extensive digital and simulator studies, four SCs, 300 Mvar each, were installed at the inverter end
to provide reactive power balance, voltage control and improve stability performance. Additional reactive
power compensation is provided by 1500 Mvar from harmonic Þlters at Foz do Iguacu, and 3000 Mvar from
harmonic Þlters and shunt capacitor banks at Ibiuna.
8.12.2 Recovery after inverter ac faults
Stability studies indicated that rapid recovery after an ac system fault would cause instability, specially during heavy load conditions in the receiving system. Solutions adopted for this problem are as follows:
a)
b)
c)
Increasing the dc voltage measurement time constant from 50Ð500 ms. This slows down the dc
power variations sufÞciently to enable SCs to maintain constant ac voltages.
Extending the restart time from 160Ð320 ms.
Limiting the current order during recovery to that of the pre-fault value. This reduces the reactive
power demand during recovery, thereby helping to reduce the risk of commutation failure.
8.12.3 Modulation for dynamic stability
Studies also indicated a critical post-fault dynamic stability problem in the region of Rio de Janeiro, where
the oscillations of generators were more marked than elsewhere. It was resolved by reactive power modulation at the inverter (g modulation), with a band-pass characteristic that is centered at the oscillation frequency of 1 Hz.
8.12.4 Sending end ac faults
The Itaipu transmission capacity is equivalent to about a sixth of the generation capacity of southeastern
Brazil. Without precautions, a solid three-phase fault in the rectiÞer ac system, and consequent loss of dc
transmission capacity, could cause a complete collapse of the receiving end system. Consequently, special
controls were introduced to rapidly restore the dc power. These are the following:
a)
b)
RectiÞer minimum a (amin) limiter (RAML). This temporarily increases amin of the rectiÞer during
and immediately following an ac fault in the sending end system. The action reduces the dc voltage
and consequently shifts the mode of the inverter into current control. This advances the inverter Þring angle to provide an increased extinction angle and, in turn, an increased margin against commutation failure. Upon fault clearance the amin limit returns gradually to its original value of 5°.
RectiÞer current regulatorÑintegrator a clamp. This modiÞes the control response at the rectiÞer in
order to reduce current overshoot. It decreases the risk of inverter commutation failure.
8.12.5 Stresses on ac Þlter arresters
The combination of a large amount of shunt compensation required at the converters and the high ac system
impedance created a low-order parallel resonance condition. Studies showed that noncharacteristic harmonics, resulting from continued converter operation during imbalanced faults, would induce overvoltages on
the third and Þfth harmonic Þlters at both converter stations. Their arresters would be stressed to approximately 10 MJ. Other arresters experience energies between 0.2 MJ and 5.0 MJ. The energy is absorbed
mainly during the fault, with the rest during the recovery period.
8.13 McNeill
This 150 MW back-to-back converter station is located near Medicine Hat in Alberta, Canada, and interconnects the ac systems of the provinces of Alberta and Saskatchewan. This is the Þrst interconnection in Canada between the western and eastern systems. The ESCR at the Saskatchewan commutation/Þlter bus can be
less than 1.0.
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The ac voltage and reactive requirements necessitate Þlters/capacitors of up to 150 Mvar (1.0 pu), switchable in six steps. To limit TOV, permanently connected surge arresters of high-energy capability are provided
to supplement the special converter controls for limiting TOVs, e.g., following load rejection. The low ESCR
required the inverter control scheme to control dc voltage rather than to keep g constant (i.e., variable g controlÑsee Part I: 3.2.3).
8.13.1 System strength
For economic reasons, reactive compensation elements and ac Þlters are connected to the tertiary buses of
the converter transformers rather than to the ac system bus. Since the commutation process is now referred to
the tertiary, the short-circuit ratios at both sides of the station are calculated at the tertiary buses and are
lower as a result. The minimum SCR on the Saskatchewan side is 1.9. The needs for capacitor shunt compensation depends on the direction of power ßow. The Saskatchewan ESCR is 1.2, when power is received,
and 0.9 when power is delivered to Alberta.
From the perspective of the Saskatchewan side, the rated dc current is higher than that corresponding to
MAP (see Part 1: 3.2.2). Consequently, the inverter control mode is constant dc voltage at a nominal g of
25°, as discussed in general terms in Part I, 3.2.3. In the steady-state, g is automatically maintained within
±1.5° of nominal by tap changing of the converter transformer: transiently, g is permitted to reduce to the
minimum setting of 17°.
In principle, on the Alberta side, the high SCR of 3.3, an ESCR of 2.6 for rectiÞer operation, and an ESCR of
2.8 for inverter operation would permit stable inverter control in the minimum g mode at the rated dc current
which is less than IMAP. However, a constant voltage inverter control mode has again been selected. In this
case, it decouples ac voltage variations on the Alberta side from disturbing the Saskatchewan ac bus. Tap
changing maintains g between 22.5° and 19°, with a transient minimum limit of 17°.
8.13.2 AC voltage control
The ac voltage on the Saskatchewan ac bus is controlled, in the steady-state, by switched shunt capacitors,
reactors and Þlters which provide up to 150 Mvar in 6 steps. The continuous control of ac voltage on either
side, by means of converter control, was precluded because corrections on one side would detrimentally
affect the voltage on the other side. However, the converters are called on to exert fast reactive power control
during transient conditions for limiting TOVs. High energy surge arresters are permanently connected to
supplement this special control mode and to act as back-up in the event of control failure.
As demonstrated when the Empress substation on the Alberta side became supplied by a single 138 kV line,
two 230 kV lines having tripped, the voltage sensitivity to reactive switching is dependent on the operating
SCR. In order to avoid hunting in the switching of reactive power banks, a control modiÞcation was made:
the amount of ac voltage change, which initiates switching, is increased during the contingency, and then is
automatically reduced when conditions return to normal.
8.13.3 Power run-back
Further to the range of voltage control in 8.13.2, the dc controls apply power run-back to automatically
reduce the dc power to 0.1 pu when the ac voltage falls below either 0.9 pu on the Alberta side or 0.85 pu on
the Saskatchewan side. There is provision for initiation of power run-back remotely, possibly from a remote
breaker trip.
8.13.4 Islanded operation
It is foreseen that a trip of the single Saskatchewan ac feed would create an islanding situation for the dc station on that side. A protective circuit will block the converters in this event. Until the protection operates, the
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capability for commutation is expected to be maintained (as in 8.7.1), so that the ac voltage controls will
continue to be effective.
8.13.5 Harmonic resonance
On the Saskatchewan side, as in other low and very low ESCR situations, there was a potential for low-order
harmonic resonanceÑin this case at the second and third harmonics. Correction has been made by an additional control loop for the third harmonic. Adjustments to the phase-locked loop in the converter controls
have made the controls immune to the second harmonic. Studies showed that, despite the relatively high
ESCR on the Alberta side, there was a possibility of third harmonic resonance. It has been avoided by the
installation of a third harmonic Þlter on the tertiary of the converter transformer.
8.13.6 Harmonic transfer
As a result of studies that showed that harmonic transfer between the two ac systems would not be excessive,
the dc station operates without a smoothing reactor. The decision has some connection with the SCRs
because it was concluded that the size of inductance, to signiÞcantly inßuence the harmonic transfer, would
be detrimental to the speed of recovery from ac faults.
200
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Annex A
(informative)
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IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
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pp. 173Ð179, Feb. 1988.
[B26] Hingorani, N. G., Nilsson, S. L., Cresap, L., Pohl, R., and Grund, C. E., ÒActive and reactive power
modulation of HVDC systems,Ó Proceedings of the IEEE Conference on Overvoltages and Compensation in
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LOW SHORT-CIRCUIT CAPACITIESÑPART II: PLANNING GUIDELINES
IEEE
Std 1204-1997
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IEEE
Std 1204-1997
IEEE GUIDE FOR PLANNING DC LINKS TERMINATING AT AC LOCATIONS HAVING
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LOW SHORT-CIRCUIT CAPACITIESÑPART II: PLANNING GUIDELINES
IEEE
Std 1204-1997
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